MIDAMERICAN ENERGY HOLDINGS CO /NEW/ - 10-K Annual Report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2004

Commission File No. 0-25551

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, IA		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 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 X No __

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of each of the registrants’ 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. X

Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Act).

Yes __ No X

All of the shares of common equity of MidAmerican Energy Holdings Company are privately held by a limited group of investors. As of January 31, 2005, 9,081,087 shares of common stock were outstanding.

TABLE OF CONTENTS

	PART I
Item 1.	Business	4
Item 2.	Properties	31
Item 3.	Legal Proceedings	32
Item 4.	Submission of Matters to a Vote of Security Holders	34

	PART II

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	35
Item 6.	Selected Financial Data	35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 8.	Financial Statements and Supplementary Data	57
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	101
Item 9A.	Controls and Procedures	101
Item 9B.	Other Information	101

	PART III

Item 10.	Directors and Executive Officers of the Registrant	102
Item 11.	Executive Compensation	104

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	108
Item 13.	Certain Relationships and Related Transactions	109
Item 14.	Principal Accountant Fees and Services	110

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	111
Signatures		116
Exhibit Index		118

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 represent plans, expectations and beliefs and are subject to risks, uncertainties and other factors. Many of these factors are outside the Company’s control and could cause actual results to differ materially from such forward-looking statements. These factors include, among others:

·	general economic and business conditions in the jurisdictions in which its facilities are located;

·	the financial condition and creditworthiness of our significant customers and suppliers;

·	governmental, statutory, regulatory or administrative initiatives or ratemaking actions affecting the Company or the electric or gas utility, pipeline or power generation industries;

·	weather effects on sales and revenue;

·	general industry trends;

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

·	fuel and power costs and availability;

·	continued availability of accessible gas reserves;

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

·	availability, term 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 Securities and Exchange Commission (“SEC”) and similar entities with regulatory oversight;

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

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

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 on seven distinct platforms: MidAmerican Energy Company (“MidAmerican Energy”), Kern River Gas Transmission Company (“Kern River”), Northern Natural Gas Company (“Northern Natural Gas”), CE Electric UK Funding (“CE Electric UK”) (which 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 23 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 the United Kingdom, 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 680,000 natural gas customers. Its natural gas pipeline subsidiaries operate interstate natural gas transmission systems with approximately 18,300 miles of pipeline in operation and peak delivery capacity of 6.4 billion cubic feet of natural gas per day. The Company has interests in 6,777 net owned megawatts of power generation facilities in operation and under construction, including 5,203 net owned megawatts in facilities that are part of the regulated return 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.

On March 14, 2000, MEHC and an investor group comprising 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, closed on a definitive agreement and plan of merger whereby the investor group, together with certain of Mr. Scott’s family members and family trusts and corporations, acquired all of the outstanding common stock of MEHC (the “Teton Transaction”).

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 the United Kingdom 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.

MidAmerican Energy

Business

MidAmerican Energy, an indirect wholly-owned subsidiary of MEHC, owns a public utility headquartered in Iowa with $5.1 billion of assets as of December 31, 2004, and operating revenues for 2004 totaling $2.7 billion. MidAmerican Energy 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, 2004, MidAmerican Energy had approximately 698,000 regulated retail electric customers and 680,000 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 franchises, certificates, permits and licenses obtained from state and local authorities. The franchises, 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.

For the year ended December 31, 2004, MidAmerican Energy derived 53% of its gross operating revenues from its regulated electric business, 37% from its regulated gas business and 10% from its nonregulated business activities. For 2003 and 2002, the corresponding percentages were 54% electric, 36% gas and 10% nonregulated; and 61% electric, 31% gas and 8% nonregulated, respectively.

Electric Operations

For the year ended December 31, 2004, regulated electric sales by MidAmerican Energy by customer class were as follows: 20% were to residential customers, 14% were to small general service customers, 27% were to large general service customers, 5% were to other customers, and 34% were wholesale sales. For the year ended December 31, 2004, regulated electric sales by MidAmerican Energy by jurisdiction were as follows: 89% to Iowa, 10% to Illinois and 1% to South Dakota.

The annual hourly peak demand on MidAmerican Energy’s electric system usually occurs as a result of air conditioning use during the cooling season. In August 2003, MidAmerican Energy reached a record hourly peak demand of 3,935 MW. For 2004, MidAmerican Energy recorded an hourly peak demand of 3,894 MW on July 20.

The following table sets out certain information concerning MidAmerican Energy’s power generation facilities based upon summer 2004 accreditation and expected accredited generating capacity of projects recently completed or under construction:

	Facility Net
	Capacity		Net MW
Operating Project ⁽¹⁾		(MW)⁽²⁾		Owned ⁽²⁾	Fuel	Location	Operation

Steam Electric Generating Facilities:
Council Bluffs Energy Center Units 1 & 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 & 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		715		372	Coal	Iowa	1981
Riverside Generation Station		135		135	Coal	Iowa	1925-61
Total steam electric generating facilities		3,967		2,869
Other Facilities:
Combustion Turbines ⁽³⁾		1,116		1,116	Gas/Oil	Iowa	1969-2003
Quad Cities Generating Station		1,748		437	Nuclear	Illinois	1974
Portable Power Modules		56		56	Oil	Iowa	2000
Moline Water Power		3		3	Hydro	Illinois	1970
Total other facilities		2,923		1,612
Total accredited generating capacity		6,890		4,481

Projects Recently Completed or Under Construction:
Greater Des Moines Energy Center ⁽³⁾		190		190	Gas	Iowa	2004
Council Bluffs Energy Center Unit 4		790		479	Coal	Iowa	2007
Northern Iowa Wind Power		53		53	Wind	Iowa	2005
Total projects recently completed or under construction		1,033		722
		7,923		5,203

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

(2)

Represents accredited net generating capability from the summer of 2004 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 2004 as approved by the Mid-Continent Area Power Pool (“MAPP”).

(3)

The Greater Des Moines Energy Center project was completed in two phases. Commercial operation in the simple cycle mode began in May 2003, resulting in 327 MW (included in “Other Facilities — Combustion Turbines” above) of accredited capacity throughout 2004. Commercial operation of the combined cycle mode began in December 2004 and additional accredited capacity is expected to be 190 MW.

MidAmerican Energy’s total accredited net generating capability in the summer of 2004 was 4,897 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 4,481 MW and the net amount of capacity purchases and sales of 416 MW. The actual amount of generation capacity available at any time may be less than the accredited capability due to regulatory restrictions, transmission constraints, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling, modifications or other reasons.

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 recently completed its combined cycle combustion turbine project and is currently constructing the 790 MW (expected accreditation) super-critical-temperature, coal-fired Council Bluffs Energy Center Unit No. 4 (“CBEC Unit 4”) and a 310 MW (nameplate rating) wind power project in Iowa. The projects will provide service to regulated retail electricity customers. MidAmerican Energy has obtained regulatory approval to include the Iowa portion of the actual costs of the generation projects in its Iowa rate base as long as actual costs do not exceed the agreed caps that MidAmerican Energy has deemed to be reasonable. If the caps are exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures above the caps, subject to regulatory review. Wholesale sales may also be made from the projects to the extent the power is not immediately needed for regulated retail service. MidAmerican Energy expects to invest approximately $1.1 billion in the CBEC Unit 4 and wind generation projects, of which $350.4 million has been invested through December 31, 2004.

MidAmerican Energy recently completed work on its Greater Des Moines Energy Center, a natural gas-fired, combined cycle plant located near Pleasant Hill, Iowa. Construction of the plant was completed in two phases. Commercial operation of the simple cycle mode began on May 5, 2003, and continued through most of 2004, providing 327 MW of accredited capacity in the summer of 2004. Commercial operation of the combined cycle mode began on December 16, 2004. The additional accredited capacity from the completion of the second phase is expected to be 190 MW. MidAmerican Energy expects the total cost of the Greater Des Moines Energy Center to be under the $357.0 million cost cap established by the Iowa Utilities Board (“IUB”).

MidAmerican Energy is currently constructing the CBEC Unit 4, a 790 MW (based on expected accreditation) super-critical-temperature, low-sulfur coal-fired 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 ownership interest is 60.67%, equating to 479 MW of output. MidAmerican Energy expects its share of the estimated cost of the project, including transmission facilities, to be approximately $737.0 million, excluding allowance for funds used during construction. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. On February 12, 2003, MidAmerican Energy executed a contract with Mitsui & Co. Energy Development, Inc. (“Mitsui”) for the engineering, procurement and construction of the plant. On September 9, 2003, MidAmerican Energy began construction of the plant, which it expects to be completed in the summer of 2007. On December 29, 2004, MidAmerican Energy received an order from the IUB approving construction of the associated transmission facilities and is proceeding with construction.

The second electric generating project currently under construction consists of wind power facilities located at two sites in north central Iowa totaling 310 MW based on the nameplate rating. 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 projected accredited capacity for these wind power facilities is approximately 53 MW. MidAmerican Energy will own and operate these facilities, which are expected to cost approximately $323.0 million, including transmission facilities and excluding the allowance for funds used during construction. As of December 31, 2004, wind turbines totaling 160.5 MW at one of the sites were completed and in service. Completion of the remaining turbines is expected by the middle of 2005. On January 31, 2005, the IUB approved ratemaking principles related to expanding the wind power project. An additional 50 MW of capacity, based on the nameplate rating, is expected to be constructed at the sites in 2005 at an estimated cost of $63.0 million.

MidAmerican Energy is interconnected with Iowa utilities and utilities in neighboring states and is party to an electric generation and transmission pooling agreement 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 facilitates operation of the transmission system, is responsible for the safety and reliability of the bulk electric system, and has responsibility for administration of the MAPP’s Open-Access Transmission Tariff.

Each MAPP participant is required to maintain for emergency purposes a net generating capability reserve of at least 15% above its system peak demand. MidAmerican Energy’s reserve margin at peak demand for 2004 was approximately 26%. MidAmerican Energy believes it has adequate electric capacity reserve through 2010, 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 appropriate 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.

Gas Operations

MidAmerican Energy is engaged in the procurement, transportation, storage and distribution of natural gas for customers in the midwest region of the United States. 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 2004, 45% of total gas delivered through MidAmerican Energy's system for end-use customers was under gas transportation services.

For the year ended December 31, 2004, regulated gas sales, excluding transportation throughput, by MidAmerican Energy by customer class were as follows: 40% were to residential customers, 20% were to small general service customers, 2% were to large general service customers and 38% were wholesale sales. For the year ended December 31, 2004, regulated gas sales, excluding transportation throughput, by MidAmerican Energy by jurisdiction were as follows: 78% to Iowa, 11% to South Dakota, 10% to Illinois and 1% to Nebraska.

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

MidAmerican Energy purchases gas supplies from producers and third party marketers. To ensure system reliability, a geographically diverse supply portfolio with varying terms and contract conditions is utilized for the 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 clause discussed below.

MidAmerican Energy has rights to firm pipeline capacity to transport 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 clause.

MidAmerican Energy is allowed to recover its cost of gas from all of its regulated gas customers through purchased gas adjustment clauses. Accordingly, MidAmerican Energy’s regulated gas customers retain the risk associated with the market price of gas. MidAmerican Energy uses several strategies to reduce the market price risk for its 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 typically replaced during the summer months when the demand for gas has historically been 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 gas purchases during the volatile winter heating season.

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 gas procurement costs to an index-based reference price. If MidAmerican Energy’s cost of 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, 2005. 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 January 31, 2005, MidAmerican Energy’s 2004/2005 winter heating season peak-day delivery of 997,058 Dth was reached on January 14, 2005. This peak-day delivery included 76% traditional sales service and 24% transportation service.

Kern River

Business

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. In 2003, a 717 mile expansion project (“2003 Expansion Project”), which was placed in service on May 1, 2003, 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.

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 pipeline, 628 miles of 36-inch 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, 2004) and Mojave Pipeline Company (“Mojave”), a wholly owned subsidiary of El Paso Corporation (“El Paso”) (approximately 23.2% as of December 31, 2004), as tenants-in-common. Kern River’s ownership percentage in the common facilities will increase or decrease pursuant to subsequently completed expansions 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.

Transportation Service Agreements

As of December 31, 2004, Kern River had under contract 1,661,575 Dth per day of capacity under long-term firm gas transportation service agreements under which the pipeline receives natural gas on behalf of shippers at designated receipt points, transports the gas on a firm basis up to each shipper’s maximum daily quantity and delivers thermally equivalent quantities of gas at designated delivery points. Each shipper pays Kern River the aggregate amount specified in its long-term firm 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 gas transported.

With respect to Kern River’s mainline facilities in existence prior to the 2003 Expansion Project, at December 31, 2004, Kern River had 27 long-term firm gas transportation service agreements with 16 shippers, for a total of 848,949 Dth per day of capacity. All but one of these long-term firm gas transportation service agreements expires on or before April 30, 2017. 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 gas distribution utility which provides services in Nevada and California.

With respect to Kern River’s 2003 Expansion Project, at December 31, 2004, Kern River had 19 long-term firm 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 gas transportation service agreements expiring on April 30, 2018. The remaining 17% of capacity is contracted for 10 years, with five long-term firm 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.

Northern Natural Gas

Business

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 16,500 miles of natural gas pipelines with a design capacity of 4.4 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 small 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 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.

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 70% of Northern Natural Gas’ firm transportation contracts extend beyond 2007.

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 2004, approximately 85% of Northern Natural Gas’ revenue was from capacity charges under firm transportation and storage contracts and approximately 80% of that revenue was from LDCs. In 2004, approximately 71% of Northern Natural Gas’ 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 2004, approximately 19% of Northern Natural Gas’ 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 at Garner, Iowa and Wrenshall, Minnesota. The three underground natural gas storage facilities and Northern Natural Gas’ two LNG storage peaking units have a total working 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 loadswing requirements. In 2004, approximately 10% of Northern Natural Gas’ revenue was generated from storage services.

Northern Natural Gas’ system is characterized by significant seasonal swings in demand, which provide opportunities to deliver high value-added services. 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, Pony Express Pipeline 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, other parts of the Midwest and Texas.

Kern River and Northern Natural Gas Competition

Each of Kern River and Northern Natural Gas has several customers who account for greater than 10% of its revenue. The loss of any one or more of these, if not replaced, could have a material adverse effect on Kern River’s and Northern Natural Gas’ respective businesses.

Pipelines compete on the basis of cost (including both transportation costs and the relative costs of the natural gas they transport), flexibility, reliability of service and overall customer service. Industrial end-users often have the ability to choose from alternative fuel sources 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 serving the southern California, Las Vegas, Nevada and Salt Lake City, Utah market areas, in order to market any unutilized or unsubscribed capacity. Kern River provides its customers with supply diversity through pipeline interconnections with Northwest Pipeline, Colorado Interstate, Overland Trail Pipeline, and Questar Pipeline. These interconnections, in addition to the direct interconnections to natural gas processing facilities, allow Kern River to access natural gas reserves in Colorado, northwestern New Mexico, Wyoming, Utah and the Western Canadian Sedimentary Basin.

Kern River is the only interstate pipeline that presently delivers natural gas directly from a gas supply basin into the intrastate California market, which enables its 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 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 expanded at comparatively lower costs 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 under expansion rates and settlement rates also provide customers with greater rate certainty. Kern River’s market position depends to a significant degree, however, on the availability and favorable price of gas produced in the Rocky Mountain area, an area that in recent years has attracted considerable expansion of pipeline capacity serving markets other than California and Nevada. In addition, Kern River’s 2003 Expansion Project 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.

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 relatively high load factor throughput, which lowers the cost per unit of transportation. Although Northern Natural Gas has experienced pipeline system bypass 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 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 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 expansion. 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 the construction of new power and ethanol plants. Over the last five years, Northern Natural Gas has contracted approximately 281 mmcf per day of firm volume on its system from such new facilities, of which approximately 262 mmcf per day is currently in service and approximately 19 mmcf per day is scheduled to begin service in 2005.

Pipeline Development Project

MEHC and a subsidiary, Alaska Gas Transmission Company, LLC (“Alaska Gas”), are 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 which would be subject to FERC regulation and would extend from the North Slope area near Prudhoe Bay, Alaska south to the Alaska-Yukon border near Beaver Creek, Alaska. The State of Alaska is expected to select a preferred party for the project by the end of the second quarter of 2005. If either MEHC or Alaska Gas are selected, further approvals, including from FERC, would be required and significant development and construction risk would remain with respect to the pipeline project.

CE Electric UK

Business

CE Electric UK, an indirect wholly-owned subsidiary of MEHC, owns, primarily, two companies that distribute electricity in the United Kingdom, Northern Electric and Yorkshire Electricity. Northern Electric and Yorkshire Electricity, collectively, are the third largest electricity distribution business in the United Kingdom, serving more than 3.7 million customers in an area of approximately 10,000 square miles.

Electricity Distribution

Northern Electric’s and Yorkshire Electricity’s operations consist primarily of the distribution of electricity in the United Kingdom. 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 service areas are connected to the Northern Electric and Yorkshire Electricity networks and electricity can only be delivered 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 “Use of System Agreement”, which Northern Electric and Yorkshire Electricity separately entered into with the various suppliers of electricity in their respective distribution areas. One such supplier, Innogy Holdings plc (“Innogy”) and certain of its affiliates, represented approximately 47% of the total revenues of Northern Electric and Yorkshire Electricity in 2004. The fees that may be charged by Northern Electric and Yorkshire Electricity for use of their distribution systems are controlled by a formula prescribed by the United Kingdom’s electricity regulatory body that limits increases (and may require decreases) based upon the rate of inflation in the United Kingdom and other regulatory action.

At December 31, 2004, 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 64,000 kilometers of underground cables. In addition to the circuits referred to above, at December 31, 2004, Northern Electric’s and Yorkshire Electricity’s distribution facilities also included approximately 58,000 transformers and approximately 750 primary substations. Substantially all substations are owned, with the balance being leased from third parties, most of which have 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 on behalf of Northern Electric’s and Yorkshire Electricity’s distribution businesses 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 20% interest. The project, operated by Origin Energy of Australia, is nearing completion and includes an approximately 145 kilometer subsea pipeline across the Bass Strait off southern Victoria. The Bass Project is expected to be fully operational in 2005. The gas from the project will be sold to Origin Energy’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. Also in the Bass Basin, CE Gas holds a 23.5% interest in the Trefoil discovery. This gas and gas liquids discovery was drilled in late 2004 and the commercial development potential is currently under evaluation. The Otway project, in which CE Gas holds a 6% interest, is operated by Woodside of Australia. This project received construction approval during 2004. Construction has now commenced with first production expected in 2006. Further prospecting in the three Otway Basin exploration permits in which CE Gas holds a 6% interest continues to be investigated. CE Gas also has a one-third interest in permit EP 437 in the onshore northern Perth Basin. The permitting process for this project was successfully completed in 2004.

In the United Kingdom, CE Gas continues to retain its 5% interest in the Victor Field, which is a gas field located in the North Sea, and during 2004, successfully applied for, and was granted, a new exploration permit in which CE Gas has a 100% interest.

In Poland, CE Gas retains its development interest in the Polish Trough. CE Gas, together with its joint venture partners FX Energy and the Polish Oil and Gas Company, has drilled the Zaniemysl #3 well in the Fences I Concession. This resulted in a commercial gas discovery early in 2004 in which CE Gas holds a 24.5% interest. This discovery is currently being developed and it is anticipated that the field will be on production in early 2006.

CalEnergy Generation-Foreign

Business

The CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of the Upper Mahiao, Mahanagdong and Malitbog projects, which are geothermal power plants located on the island of Leyte in the Philippines, and the Casecnan project, a combined irrigation and hydroelectric power generation project located in the central part of the island of Luzon in the Philippines. 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, 2004:

Facility

Net

Power

Capacity

Net MW

Contract

Purchaser/

Project⁽¹⁾

(MW)⁽²⁾

Owned⁽²⁾

Fuel

Expiration

Guarantor⁽³⁾

Upper Mahiao

119

Geo

2006

PNOC-EDC/ROP

Mahanagdong

155

150

Geo

2007

PNOC-EDC/ROP

Malitbog

216

Geo

2007

PNOC-EDC/ROP

Casecnan ⁽⁴⁾

150

Hydro

2021

NIA/ROP

Total International Projects

640

635

(1)	All projects are located in the Philippines, are governed by contracts which are mainly payable in U.S. dollars 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 undertakings of the ROP support PNOC-EDC’s and NIA’s respective obligations for each project.

(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.

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 18, 2006, the end of the ten-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 on a “take-or-pay” basis, 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 entered into on 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 5% 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. PNOC-EDC’s payment requirements, and its other obligations under the Upper Mahiao agreement, are supported by the ROP through a performance undertaking.

The Mahanagdong project is a 155 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 ten 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 entered into on August 31, 2003, CE Luzon and PNOC-EDC agreed that the plant capacity would equal the contractually specified level, which declines from approximately 155 MW in 2004 to approximately 153 MW in the last year of the cooperation period. The capacity fees are approximately 97% of total revenue at the contractually agreed capacity levels and the energy fees are approximately 3% of such total revenue. PNOC-EDC’s payment requirements, and its other obligations under the Mahanagdong agreement, are supported by the ROP through a performance undertaking.

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 electrical energy produced by the facility is sold to PNOC-EDC on a “take-or-pay” basis. These capacity payments equal 100% of total revenue. Pursuant to an amendment to the Malitbog energy conversion agreement entered into on 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 will generally be made to a peso-denominated account and will be used to pay peso-denominated operation and maintenance expenses with respect to the Malitbog project and Philippine withholding taxes, if any, on the Malitbog project’s debt service. The ROP has entered into a performance undertaking, which provides that all of PNOC-EDC’s obligations pursuant to the Malitbog energy conversion agreement carry the full faith and credit of, and are affirmed and guaranteed by, the ROP. The Malitbog energy conversion agreement ten 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.

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 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. The seasonality of rainfall patterns and the variability of rainfall from year to year, all of which are outside the control of CE Casecnan, 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. Summarized below are significant provisions of the Project Agreement as modified by the Supplemental Agreement.

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.

The ROP has provided a Performance Undertaking under which NIA’s obligations under the Project Agreement, as supplemented by the Supplemental Agreement, are guaranteed by the full faith and credit of the ROP. The Project Agreement and the Performance Undertaking provide for the resolution of disputes by binding arbitration in Singapore under international arbitration rules.

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

Business

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, 2004:

Facility

Power

Net

Purchase

Capacity

Agreement

Power

Operating Project

(MW)⁽¹⁾

Owned⁽¹⁾

Fuel

Location

Expiration

Purchaser⁽²⁾

Cordova

537

Gas

Illinois

2017

El Paso

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

Varies

Various

Saranac

240

Gas

NewYork

2009

NYSE&G

Power Resources

212

106

Gas

Texas

2005

ONEOK

Yuma

Gas

Arizona

2024

SDG&E

Roosevelt Hot Springs

Geo

Utah

2020

UP&L

Total Domestic Operating Projects

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)	El Paso; Southern California Edison Company (“Edison”); New York State Electric & Gas Corporation (“NYSE&G”); ONEOK Energy, Marketing and Trading Company, L.P. (“ONEOK”); San Diego Gas & Electric Company (“SDG&E”); and Utah Power & Light Company (“UP&L”).

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. Cordova Energy entered into a power purchase agreement with a unit of El Paso, under which El Paso will purchase all of the capacity and energy from the project until December 31, 2019. 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 from El Paso 50% of the output of the Cordova Project, reducing El Paso’s purchase obligation to 50% of the output during such contract year. Cordova Energy exercised such option for the contract year ended May 14, 2004, and the recalled output was sold to MidAmerican Energy. Cordova Energy did not exercise the recall option for the contract year which commenced on May 15, 2004, and El Paso is required to purchase 100% of the capacity and energy from the project for the current contract year and, subject to future exercises of the recall option, for the remainder of the term of the power purchase agreement. The Company is aware there have been public announcements that El Paso’s financial condition has deteriorated as a result of, among other things, reduced liquidity and will continue to monitor the situation.

MEHC has a 50% ownership interest in CE Generation, LLC (“CE Generation”) whose affiliates currently operate ten geothermal plants in the Imperial Valley in California (the “Imperial Valley Projects”). The Imperial Valley Projects include the “Salton Sea Projects” consisting of the Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V projects and the “Partnership Projects” consisting of the Vulcan, Elmore, Leathers, Del Ranch and CE Turbo projects.

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, Salton Sea V and CE Turbo projects), 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 commencing May 1, 2002 for a five-year period. Following the five-year period, the energy payments revert back to Edison’s Avoided Cost of Energy.

For the years ended December 31, 2004, 2003 and 2002, Edison’s average Avoided Cost of Energy was 5.9 cents per kWh, 5.4 cents per kWh and 3.5 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.

On May 20, 2003, Salton Sea Power LLC (“Salton Sea Power”) entered into a power sales agreement with Riverside. Under the terms of the agreement, Salton Sea Power sells up to 20 MW of energy generated from the Salton Sea V project to Riverside. Sales under the agreement commenced June 1, 2003 and will terminate May 31, 2013.

Pursuant to 33-year power sales agreements, the Salton Sea V and CE Turbo projects had sold a portion of their net output to CalEnergy Minerals LLC (“Minerals”) for the Zinc Recovery Project’s full electrical energy requirements. The agreements provide for energy payments based on the market rates available to the Salton Sea V and CE Turbo projects, adjusted for wheeling costs. On September 10, 2004, Minerals ceased operations of the Zinc Recovery Project. Accordingly, except for sales during the dismantling and decommissioning phases of the Zinc Recovery Project, no further sales to Minerals are expected. The Salton Sea V project sells its remaining output and the CE Turbo project sells its available power under the transaction agreement as described in the next paragraph.

Pursuant to a transaction agreement dated January 29, 2003, the Salton Sea V project and the CE Turbo project began selling available power to TransAlta USA Inc. (“TransAlta”) on February 12, 2003 based on percentages of the Dow Jones SP-15 Index. The transaction agreement shall continue until the earlier of (a) 30 days following a written notice of termination and (b) any other termination date mutually agreed to by the parties. No such notice of termination has been given by either party.

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, ArcLight Capital Holdings and General Electric Capital Corporation. 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 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. The agreement commenced October 1, 2003 and expires December 31, 2005. Under the terms of the agreement, Power Resources, as an exempt wholesale generator ("EWG"), sells its electricity and capacity to ONEOK for a fixed amount per kW-month plus a variable operating and maintenance fee per MWh. In addition, ONEOK pays annual turbine start-up costs.

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 PPA"). MEHC has guaranteed all of the obligations of YCA under the Yuma PPA or any other agreement with SDG&E relating to or arising out of the Yuma PPA. YCA also has executed steam sales contracts with Queen Carpet, Inc. to act as its thermal host.

The Roosevelt Hot Springs project is a geothermal steam field which supplies geothermal steam to a 23 net MW power plant owned by UP&L located on the Roosevelt Hot Springs property under a 30-year steam sales contract expiring in 2020. The Company obtained a cash prepayment under a pre-sale agreement with UP&L whereby UP&L paid in advance for the steam produced by the steam field. MEHC guarantees the performance of this subsidiary and must make certain penalty payments to UP&L if the steam produced does not meet certain quantity and quality requirements.

Zinc Recovery Project

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”).

The Zinc Recovery Project began limited production during December 2002 and continued limited production until September 10, 2004. Efforts to increase production had continued since the Zinc Recovery Project was placed in service with an emphasis on process modification. Management had been assessing the long-term economic viability of the Zinc Recovery Project in light of continuing cash flow deficits and operating losses and the efforts to increase production, and had continued to evaluate the expected impact of the planned improvements to the extraction process during the third quarter of 2004. Furthermore, management had been exploring other operating alternatives, such as establishing strategic partnerships and consideration of ceasing operations of the Zinc Recovery Project.

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 are being dismantled and sold and certain employees of the operator of the Zinc Recovery Project have been paid one-time termination benefits. Implementation of a disposal plan began in September 2004 and will continue in 2005. Refer to Note 3 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Form 10-K for additional discussion regarding the Company’s discontinued operations.

Development Projects

MEHC’s indirect wholly-owned subsidiary, CE Obsidian Energy LLC (“Obsidian”), is evaluating the development of a 185 net MW geothermal facility in the Imperial Valley in California. Substantially all of the output of the facility would be sold to the Imperial Irrigation District (“IID”) pursuant to a power purchase agreement. TransAlta is currently funding 50% of the development costs of this project. Significant development and construction risk remains with this project.

HomeServices

Business

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, mortgage banking, title and closing services and other related services. 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, 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, Missouri; Des Moines, Iowa; Omaha and Lincoln, Nebraska; Birmingham and Auburn, Alabama; Tucson, Arizona; Winston-Salem and Charlotte, North Carolina; Louisville and Lexington, Kentucky; Annapolis, Maryland; Atlanta, Georgia; Miami, Florida and Springfield, Missouri.

Acquisitions

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 operating platforms are subject to a number of federal, state, local and international regulations.

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 could be restricted.

With the elimination of its energy adjustment clause in Iowa in 1997, MidAmerican Energy is financially exposed to movements in energy prices. Although MidAmerican Energy believes it has sufficient generation under typical operating conditions for its retail electric needs, a loss of adequate generation by MidAmerican Energy requiring the purchase of replacement power at a time of high market prices could subject MidAmerican Energy to losses on its energy sales.

Under three settlement agreements between MidAmerican Energy, the Iowa Office of Consumer Advocate (“OCA”) and other intervenors, approved by the IUB, MidAmerican Energy has agreed not to seek a general increase in electric rates prior to 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 request or support 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 the first settlement agreement, which was approved by the IUB on December 21, 2001, and is 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 is recorded as a regulatory liability. The second settlement agreement, which was filed in conjunction with MidAmerican Energy’s application for ratemaking principles on its wind power project and was approved by the IUB on October 17, 2003, provides 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.

The third settlement agreement was approved by the IUB on January 31, 2005, in conjunction with MidAmerican Energy’s proposed expansion of its wind power project by up to 90 MW. This settlement 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. In addition, the OCA agreed to commit not to seek any decrease in Iowa electric base rates to become effective before January 1, 2012. The total capacity added as the result of the wind expansion project is currently projected to be 50 MW.

The regulatory liabilities created by the three settlements 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 in amounts equal to the allowance for funds used during construction 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.

Illinois bundled electric rates are frozen until 2007, subject to certain exceptions allowing for increases, at which time bundled rates may be increased or decreased by the Illinois Commerce Commission. Illinois law provides that, through 2006, Illinois earnings above a computed level of return on common equity are to be shared equally between regulated retail electric customers and MidAmerican Energy. MidAmerican Energy’s computed level of return on common equity is based on a rolling two-year average of the Monthly Treasury Long-Term Average Rate, as published by the Federal Reserve System, plus a premium of 8.5% for 2000 through 2004 and a premium of 12.5% for 2005 and 2006. The two-year average above which sharing must occur for 2004 is 13.57%. The law allows MidAmerican Energy to mitigate the sharing of earnings above the threshold return on common equity through accelerated recovery of electric assets.

The FERC has undertaken several measures to increase competition in the markets for wholesale electric energy, including efforts to foster the development of regional transmission organizations (“RTO”) in its Order No. 2000 issued December 1999 and its July 2002 proposed rulemaking that would implement a standard market design (“SMD”) for wholesale electric markets.

If implemented, the FERC’s July 2002 proposed rule for SMD would require sweeping changes to the use and expansion of the interstate transmission and wholesale bulk power systems in the United States. However, it is unclear when or even whether the FERC will issue a final rule and what form the final rule would ultimately take. In response to significant criticism of its proposed rule, the FERC subsequently indicated that it had changed its proposal and would adopt a flexible approach to SMD that would accommodate regional differences. Any final rule on SMD or similar FERC action could impact the costs of MidAmerican Energy’s electricity and transmission products. Such FERC action could directly or indirectly influence how transmission services are priced, the availability of transmission services, how transmission services are obtained and market prices for electricity in markets in which MidAmerican Energy buys and sells electricity. Although MidAmerican Energy is not presently a member of an RTO, two RTOs - Midwest Independent System Operator and PJM Interconnection - are directly interconnected with MidAmerican Energy’s transmission facilities. MidAmerican Energy cannot predict what impact, if any, the evolution of these RTOs, or others, may have on how wholesale electricity is bought and sold, as well as the geographic scope of the wholesale marketplace in which MidAmerican Energy buys or sells electricity.

On June 3, 2004, the FERC’s Division of Operational Investigations of the Office of Market Oversight and Investigations 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, (2) codes of conduct, and (3) transmission practices. The FERC has commenced several such audits of utilities in 2003 and 2004. The audit is on-going, and MidAmerican Energy expects it to be completed within the first half of 2005. 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.

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. In accordance with the FERC order, MidAmerican Energy’s market-based sales became subject to refund beginning November 1, 2004, and will remain so until the matter is resolved. 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.

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.

Kern River’s tariff rates were 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 are set using a “levelized cost-of-service” methodology so that the rate is constant over the contract period. This is achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense decreases.

Kern River was required to file a 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 a 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. Since its last rate case, Kern River has increased the capacity of its system from 724,500 Dth per day to 1,755,575 Dth per day at a cost of approximately $1.3 billion resulting in a total rate base of approximately $1.8 billion. The rate increase became effective on November 1, 2004, subject to refund, and the FERC set a procedural order with a hearing scheduled for March 2005.

On February 10, 2005, Kern River received notice from the Office of Market Oversight and Investigations of the FERC that it is instituting a non-public audit to determine Kern River's compliance with the FERC's standards of conduct in regards to communications with any of Kern River's marketing and energy affiliates. The time period of the audit generally covers September 22, 2004, to the present although some questions cover time periods from November 25, 2003. Kern River understands that virtually all interstate pipelines are expected to be audited by the FERC in 2005. Kern River believes it is in compliance with the standards of conduct in all material respects and the outcome of this audit is not expected to have a material effect on Kern River's results of operations, financial position or cash flows.

Northern Natural Gas has implemented 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 request for increased rates with the FERC. The rate increase is primarily attributable to four main cost areas: the capital investment made by Northern Natural Gas in the five years since its last rate case, an increase in Northern Natural Gas’ depreciation rates, increased return on equity, and changes in the level of contract entitlement. The rate filing provides evidence in support of a $71 million increase to Northern Natural Gas’ annual revenue requirement. However, Northern Natural Gas chose to effectuate only $55 million of the increase. Northern Natural Gas’ new rates went into effect November 1, 2003, subject to refund.

Additionally, on January 30, 2004, Northern Natural Gas filed with the FERC to increase its revenue requirement by an incremental $30 million to that requested in the May 1, 2003 filing. The increased revenue requirement is primarily attributable to ongoing pipeline integrity initiative costs that Northern Natural Gas has undertaken since the May 1, 2003 rate filing. The FERC suspended the rate increase until August 1, 2004 and consolidated the 2003 and 2004 rate cases due to the similarity of issues in both cases and the updated costs. On July 29, 2004, Northern Natural Gas notified the FERC that, in furtherance of settlement negotiations, Northern Natural Gas was not putting the rate increase into effect on August 1, 2004, but reserved its statutory right to put the suspended rates into effect at a later date. Northern Natural Gas’ implemented the new rates on November 1, 2004, subject to refund.

On February 16, 2005, Northern Natural Gas reached a tentative agreement with the majority of its customers to settle the consolidated rate cases. Definitive terms of the settlement must be agreed by all settling parties and must then be documented in a settlement agreement which must be agreed to by all settling parties. Thereafter, the settlement must be certified by the presiding administrative law judge and approved by the FERC. The terms of the agreement in principle provide for an annual revenue increase of $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. As a result of the settlement, Northern Natural Gas will be required to refund an amount generally reflecting the difference between the rate increases implemented on November 1, 2003 and November 1, 2004 and the final settled revenue amounts.

Additional proposals and proceedings that might affect the interstate 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.

Other United States Regulation

The Public Utility Regulatory Policies Act of 1978, as amended ("PURPA") and the Public Utility Holding Company Act of 1935, as amended (“PUHCA”), are two of the laws (including the regulations thereunder) that affect MEHC and certain of its subsidiaries’ operations. PURPA provides to qualified facilities (“QF”) certain exemptions from federal and state laws and regulations, including organizational, rate and financial regulation. PUHCA extensively regulates and restricts the activities of registered public utility holding companies and their subsidiaries. Any legislation altering PUHCA or PURPA, if adopted, could adversely impact the Company's existing domestic projects.

The Company is currently exempt from regulation under all provisions of PUHCA, except the provisions that regulate the acquisition of securities of public utility companies, based on the intrastate exemption in Section 3(a)(1) of PUHCA. In order to maintain this exemption, MEHC and each of its public utility subsidiaries from which it derives a material part of its income (currently only MidAmerican Energy) must be predominantly intrastate in character and organized in and carry on MEHC’s and MidAmerican Energy’s respective utility operations substantially in MidAmerican Energy’s state of organization (currently Iowa). Except for MidAmerican Energy’s generating plant assets, the majority of the Company's domestic power plant operations and all of its foreign utility operations are not public utilities within the meaning of PUHCA as a result of their status as QFs under PURPA (with the Company’s ownership interest therein limited to 50%), EWGs or foreign utility companies, or are otherwise exempted from the definition of “public utility” under PUHCA. Although the Company believes that it will continue to qualify for exemption from additional regulation under PUHCA, it is possible that as a result of the expansion of its public utility operations, loss of exempt status by one or more of its domestic power plants or foreign utilities, or amendments to PUHCA or the interpretation of PUHCA, the Company could become subject to additional regulation under PUHCA in the future. There can be no assurances that such regulation would not have a material adverse effect on the Company.

In the event the Company was unable to avoid the loss of QF status for one or more of its affiliate’s facilities, such an event could result in termination of a given project’s power sales agreement and a default under the project subsidiary’s project financing agreements, which, in the event of the loss of QF status for one or more facilities, could have a material adverse effect on the Company.

Regulatory requirements applicable in the future to nuclear generating facilities could adversely affect the results of operations of MEHC and MidAmerican Energy, in particular. The Company is subject to certain generic risks associated with utility nuclear generation, including risks arising from the operation of nuclear facilities and the storage, handling and disposal of high-level and low-level radioactive materials; risks of a serious nuclear incident; limitations on the amounts and types of insurance commercially available in respect of losses that might arise in connection with nuclear operations; and uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The Nuclear Regulatory Commission (“NRC”) has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. Revised safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at nuclear plants, including the Quad Cities units, in which MidAmerican Energy has an ownership interest, and additional such expenditures could be required in the future.

Pipeline Safety Regulation

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 system. 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 facilities 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 things, 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 which could pose a hazard to navigation or public safety. In addition, the amendments narrowed the scope of its gas pipeline exemption pertaining to underground storage tanks under the Resource Conservation and Recovery Act. The Company believes its pipeline operations 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 a major new final rule, effective February 14, 2004, that requires interstate pipeline operators to: develop comprehensive integrity management programs, identify applicable threats to pipeline segments that could impact High Consequence Areas, assess these segments, and provide ongoing mitigation and monitoring. The Company believes its pipeline operations comply in all material respects with the PSIA.

CE Electric UK

Since 1990, the electricity generation, supply and distribution industries in Great Britain have been privatized, and competition has been introduced in generation and supply. 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 service 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 holders of an electricity distribution license. The residual elements of the electricity supply licenses were transferred to Innogy 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 (the “Yorkshire Swap”).

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.

Most of the revenue of the DLHs in the United Kingdom is controlled by a distribution price control formula which is set out in the license of each DLH. It has been the practice of the Office of Gas and Electricity Markets (“Ofgem”) (and its predecessor body, the Office of Electricity Regulation), to review and reset the formula at five year intervals, although the formula 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 United Kingdom’s competition authority, 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 Price 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 2000 (and through March 31, 2005, will continue to be set) at 3%. 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 is 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 most efficient licensees;

·	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 1999, the allowed revenue of Northern Electric’s distribution business was reduced by 24%, in real terms, and the allowed revenue of Yorkshire Electricity’s distribution business was reduced by 23%, in real terms, with effect from April 1, 2000.

Ofgem’s process of reviewing each DLH’s existing price control formula, with a revised formula for each DLH (including Northern Electric and Yorkshire Electricity) to take effect from April 1, 2005 for an expected period of five years was recently completed. As a result of the review, 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. The Xd factor was set at zero. 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 may depend on the successful implementation of revised cost reporting guidelines to be prescribed by Ofgem and applied by all DLHs. 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.

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 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 a £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.

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 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.

CalEnergy Generation-Foreign

In June 2004, Philippine President Gloria Macapagal-Arroyo was re-elected for a six-year term, through June 2010. President Macapagal-Arroyo has announced a plan to pursue policies targeting balanced economic growth, strong market-based industry, and poverty alleviation. In connection with those policies, the Philippine Department of Energy has announced an energy plan focused on attaining a 100 percent electrification level throughout the Philippines, further developing and utilizing renewable energy sources for power and electrification, and enhancing private sector participation in all energy activities.

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 Philippines power industry as a whole, the effect of which is not yet determinable or estimable.

In connection with an interagency review of approximately 40 independent power project contracts in the Philippines pursuant to EPIRA, in 2003 the Casecnan project (together with four other unrelated projects) had reportedly been identified as raising legal and financial questions and, with those projects, had been prioritized for renegotiation. As part 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. MEHC’s indirect subsidiaries’ Leyte Projects also had reportedly been identified as raising financial questions. In connection with the entering into of amendments to the energy conversion agreement for each of the Leyte Projects with PNOC-EDC, the Company believes that any issues raised by the interagency review of independent power producers in the Philippines with respect to the Leyte Projects have been resolved.

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. QF status under PURPA provides two primary benefits. First, regulations under PURPA exempt QFs from PUHCA, the FERC rate regulation under 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 require 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. There can be no assurance that the QF status of such CalEnergy Generation - Domestic facilities will be maintained.

Cordova Energy and Power Resources are exempt from regulation under PUHCA because they are EWGs. PUHCA provides that a EWG is not considered to be an electric utility company. A EWG is permitted to sell capacity and electricity in the wholesale markets, but not in the retail markets.

If an 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. On July 29, 2002, HUD issued a proposed regulation under the Real Estate Settlement and Procedures Act.(“RESPA”) HUD has characterized the proposal as “fundamentally changing the way in which payments to mortgage brokers are recorded and reported to consumers,” “significantly” improving the disclosure of settlement costs on the Good Faith Estimate making it firmer and more usable, and “removing regulatory barriers to allow guaranteed packages of settlement services and mortgages to be made available to consumers.” The proposal was submitted to the Office of Management and Budget on December 16, 2003, and was voluntarily withdrawn by HUD on March 22, 2004. The House Committee on Financial Services, the Senate Committee on Banking, Housing and Urban Affairs and HUD each has indicated that reforming the RESPA regulation is a priority in 2005. It is unknown whether a proposed rule will be introduced or finalized in 2005. 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 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 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.

Clean Air Standards

MidAmerican Energy’s generating facilities are 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.

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 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 in the area 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 is in attainment of the ozone standards and the fine particulate standards.

On December 4, 2003, the EPA announced the development of its Interstate Air Quality Rule, now known as the Clean Air Interstate Rule, a proposal to require coal-burning power plants in 29 states, including Iowa, and the District of Columbia to reduce emissions of sulfur dioxide (“SO₂”) and nitrogen oxides (“NO_X”) in an effort to reduce ozone and fine particulate matter in the Eastern United States. It is likely that MidAmerican Energy’s coal-burning facilities will be impacted by this proposal.

In December 2000, the EPA concluded that mercury emissions from coal-fired generating stations should be regulated. The EPA is currently considering two regulatory alternatives that would reduce emissions of mercury from coal-fired utilities. One of these alternatives would require reductions of mercury from all coal-fired facilities greater than 25 MW through application of Maximum Achievable Control Technology with compliance assessed on a facility basis. The other alternative would regulate the mercury emissions of coal-fired facilities that pose a health hazard through a market based cap-and-trade mechanism similar to the SO₂ allowance system. The EPA is currently under a deadline to finalize the mercury reduction rule by March 2005.

The Clean Air Interstate Rule or the mercury reduction rule 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 the “Clear Skies Initiative,” and other pending legislative proposals that contemplate 70% to 90% reductions of SO₂, NO_X and mercury, as well as possible new federal regulation of carbon dioxide and other gasses that may affect global climate change.

Depending on the outcome of the final Clean Air Interstate Rule and the mercury reduction rule or any superseding legislation by Congress, MidAmerican Energy may be required to install control equipment on its generating stations, purchase emission allowances or decrease the number of hours during which its generating stations operate. However, until final regulatory or legislative action is taken, the impact of the regulations on MidAmerican Energy cannot be predicted.

MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be required to meet emissions reductions as contemplated 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 NO_X 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 Iowa Consumer Advocate Division of the Department of Justice. 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 $325.0 million, then MidAmerican Energy may seek to recover the additional expenditures from customers. At this time, MidAmerican Energy does not expect these capital expenditures to exceed such amount.

Under the 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 support 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. However, on August 27, 2003, the EPA announced changes to its NSR rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. The EPA concluded equipment that is repaired, maintained or replaced with an expenditure not greater than 20 percent of the value of the source will not trigger the NSR provisions of the Clean Air Act. A number of states and local air districts challenged the EPA’s clarification of the NSR rule and a panel of the U.S. Circuit Court of Appeals for the District of Columbia Circuit issued an order on December 24, 2003, staying the EPA’s implementation of its clarifications of the equipment replacement rule. On July 1, 2004, the EPA published a notice of stay of the final equipment replacement rule in the Federal Register, consistent with the judicial stay. Additionally, on the same date, the EPA published a Notice of Reconsideration and Request for Comment on the equipment replacement rule in response to the Petitioners’ legal challenges. Until such time as the EPA takes final action on the equipment replacement rule, the previous rules without the clarified exemption remain in effect.

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 informed MidAmerican Energy that existing on-site storage capability at Quad Cities Station is sufficient to permit interim storage in 2005. For Quad Cities Station, Exelon Generation has begun to develop 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. Exelon Generation has completed the bulk of the construction work on the first pad and expects the first cask loading to take place in 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 2004 was $8.3 million.

United Kingdom

CE Electric UK’s businesses are subject to extensive regulatory requirements with respect to the protection of the environment.

The United Kingdom government introduced new contaminated land legislation in April 2000 that requires local governmental authorities to put in place a program for investigating land in their area in order to identify contamination. Local authorities (and the Environment Agency where controlled waters are affected) can enforce remedial action where such contamination of land poses a threat to the greater environment. If the “person” who contaminated the land cannot be found, the land owner will be held responsible.

The UK local authorities have not identified any CE Electric UK sites that require any action under these regulations. CE Electric UK evaluations of three potential sites confirm this conclusion. A project with an environmental remediation company is in progress at one of these sites where there is an agreement to reduce pockets of localized contamination to an acceptable standard.

The Environmental Protection Act (Disposal of PCB’s and other Dangerous Substances) Regulations 2001 were introduced on May 5, 2000. The regulations required that transformers containing over 50 parts per million of PCB’s and other dangerous substances be registered with the Environment Agency. Transformers containing 500 parts per million had to be de-contaminated by December 31, 2000. As of December 31, 2004, CE Electric UK had 360 transformers containing between 50 and 500 parts per million of such substances registered with the Environment Agency and is continuing with its sampling, labeling and registration program. CE Electric UK believes it is in compliance and these regulations are not expected to have a material impact on the Company.

The 1998 Groundwater Regulations seek to prevent listed hazardous substances from entering groundwater and strengthens the United Kingdom Environment Agency’s powers to require additional protective measures, especially in areas of important groundwater supplies. Mineral oils and hydrocarbons are included in the list of more tightly controlled substances (“List I substances”). This affects the high voltage fluid filled electricity cable network incorporating an insulating fluid that is currently in List I. The existing voluntary Operating Code of Practice, as agreed between the Environment Agency and companies in the electricity industry, is undergoing revision to address the regulatory changes. The existing voluntary Operating Code of Practice is, and any revised Operating Code of Practice will be, incorporated into the operating practices of Northern Electric and Yorkshire Electricity. Any revisions which are made are not expected to have a material impact on the Company.

The Oil Storage Regulations became effective in 2002 and require the phased introduction of secondary containment measures (bunding) for all above ground oil storage locations where the capacity is more than 200 liters. The primary containers must be in sound condition, leak free, and positioned away from vehicle traffic routes. The secondary containment must be impermeable to water and oil (without drainage valve) and be subject to routine maintenance. The capacity of the bund must be sufficient to hold up to 110% of the largest stored vessel or 25% of the maximum stored capacity, whichever is the greater. On March 1, 2002, these regulations came into effect for all new oil storage facilities. On September 1, 2003, the regulations became effective for existing storage facilities at “significant risk” (i.e. within 10 meters of a water course), and on September 1, 2005, the regulations come into effect for all remaining storage facilities. A detailed study of the impacts has been carried out and a plan of action prepared to ensure compliance. The Company expects that the cost of compliance with the remaining provisions of such regulations will not have a material impact.

The Electricity Act 1989 obligates either the United Kingdom Secretary of State or the Director General of Electric Supply to take into account the effect of electricity generation, transmission and supply activities on the physical environment when approving applications for the construction of overhead power lines. The Electricity Act requires CE Electric UK to consider the desirability of preserving natural beauty and the conservation of natural and man-made features of particular interest when it formulates proposals for development in connection with certain of its activities. CE Electric UK mitigates the effects its proposals have on natural and man-made features and administers an environmental assessment when it intends to lay cables, construct overhead lines or carry out any other development in connection with its licensed activities. The Company expects that the cost of compliance with these obligations and the mitigation thereof will not have a material impact.

CE Electric UK’s policy is to carry out its activities in such a manner as to minimize the impact of its works and operations on the environment, and in accordance with environmental legislation and good practice. There have not been any significant regulatory environmental compliance issues and there are no material legal or administrative proceedings pending against CE Electric UK with respect to any environmental matter.

Environmental laws and regulations in the United Kingdom currently have, and future modifications may increasingly have, the effect of requiring modification of CE Electric UK’s facilities and increasing its operating costs.

Philippines

On June 23, 1999, the Philippine Congress enacted the Philippine Clean Air Act of 1999. 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 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 Clean Air Act. The gas dispersion project was put into commercial operation in December 2003.

Employees

At December 31, 2004, the Company employed approximately 11,540 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 expires February 28, 2006, and covers approximately 1,700 employee members.

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. See Notes 6 and 23 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.

MidAmerican Energy

MidAmerican Energy’s most significant properties are its electric generation facilities. Refer to the MidAmerican Energy discussion in “Item 1. Business” of this Form 10-K for additional information about MidAmerican Energy’s generation facilities.

The electric transmission system of MidAmerican Energy at December 31, 2004, included 918 miles of 345-kV lines and 1,128 miles of 161-kV lines. MidAmerican Energy’s electric distribution system included approximately 222,300 transformers and 382 substations at December 31, 2004.

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, 2004, included approximately 21,548 miles of gas mains and services pipelines.

Kern River and Northern Natural Gas

At December 31, 2004, Kern River’s pipeline consisted of two distinguishable sections: the mainline section and the common facilities. The mainline section consists of the original 682 miles of 36-inch pipeline, 628 miles of 36-inch loop pipeline related to the 2003 Expansion Project and 68 miles of various laterals that connect to the mainline, and extends from the pipeline’s point of origination near Opal, Wyoming through the Central Rocky Mountains area into Daggett, California and is owned entirely by Kern River. The common facilities consist of the 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 (currently approximately 76.8%) and Mojave (currently approximately 23.2%) as tenants-in-common.

At December 31, 2004, Northern Natural Gas’ system was comprised of approximately 7,300 miles of mainline transmission pipelines and approximately 9,200 miles of lateral pipelines. Northern Natural Gas’ storage services are provided through the operation of three underground storage fields, in Redfield, Iowa, and Lyons and Cunningham, Kansas. Northern Natural Gas’ three underground natural gas storage facilities and two LNG storage peaking units have a total storage capacity of approximately 59 Bcf. Northern Natural Gas’ two LNG liquefaction/vaporization facilities are located near Garner, Iowa and Wrenshall, Minnesota with storage capacity of 2 Bcf each.

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.

CE Electric UK

At December 31, 2004, Northern Electric’s and Yorkshire Electricity’s electricity distribution networks (excluding service connection to consumers) on a combined basis included approximately 33,000 kilometers of overhead lines and approximately 64,000 kilometers of underground cables. In addition to the circuits referred to above, at December 31, 2004, Northern Electric’s and Yorkshire Electricity’s distribution facilities also included approximately 58,000 transformers and approximately 750 primary substations.

Other Properties

At December 31, 2004, MEHC’s most significant physical properties, other than those owned by MidAmerican Energy, Kern River, Northern Natural Gas and CE Electric UK, are its current interests in operating power facilities and its plants under construction and related real property interests, as well as leases of office space for its residential real estate brokerage operations. See “Item 1. Business” of this Form 10-K for further detail.

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.

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. Motions to dismiss the complaint, filed by various defendants including Northern Natural Gas and The Williams Companies, Inc. (“Williams”), which was the former owner of Kern River, were denied on May 18, 2001. 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. Motions to Dismiss based on various jurisdictional grounds were filed on June 4, 2004. Grynberg filed his brief and other pleadings in opposition to the Motions to Dismiss on October 22, 2004. In connection with the purchase of Kern River from 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. In November 2001, Kern River and Northern Natural Gas, along with the coordinating defendants, filed a motion to dismiss under Rules 9B and 12B of the Kansas Rules of Civil Procedure. The court denied this motion. In January 2002, Kern River and most of the coordinating defendants filed a motion to dismiss for lack of personal jurisdiction. The court has yet to rule on these motions. The plaintiffs filed for certification of the plaintiff class on September 16, 2002. On January 13, 2003, oral arguments were heard on coordinating defendants’ opposition to class certification. On April 10, 2003, the court entered an order denying the plaintiffs’ motion for class certification. 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. Class discovery is ongoing. Williams has agreed to indemnify MEHC against any liability associated with Kern River for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. Northern Natural Gas anticipates joining with other defendants in contesting certification of the plaintiff class. Kern River and Northern Natural Gas believe that this claim is without merit and that Kern River’s and Northern Natural Gas’ gas measurement techniques have been in accordance with industry standards and their tariffs.

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, shortly after the state district court dismissed the plaintiffs’ third amended petition in the original litigation which sought to certify a nationwide class. The new companion action which seeks to certify a class of royalty owners in Kansas, Colorado and Wyoming, tracking the fourth amended petition in the action referenced above, was not served until August 4, 2003. A motion to dismiss was filed on August 25, 2003. On October 9, 2003, the state district court denied the motion to dismiss; Northern Natural Gas filed its answer on November 6, 2003. Class discovery is ongoing. Northern Natural Gas anticipates joining with other defendants in contesting certification of the plaintiff class. Northern Natural Gas believes that this claim is without merit and that Northern Natural Gas’ gas measurement techniques have been in accordance with industry standards and its tariff.

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 U.S. 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. At this time, MidAmerican Energy does not believe that it has any material exposure in this lawsuit.

The original complaint in this matter, Cornerstone Propane Partners, L.P. v. Reliant, et al. (“Cornerstone”), was filed on August 18, 2003 in the United States District Court, Southern District of New York naming MidAmerican Energy and MEHC. On October 1, 2003, a second complaint, Roberto, E. Calle Gracey, et al. (“Calle Gracey”), was filed in the same court but did not name MidAmerican Energy or MEHC. On November 14, 2003, a third complaint, Dominick Viola (“Viola”), et al., was filed in the same court and named MidAmerican Energy and MEHC as defendants. On November 19, 2003, an Order of Voluntary Dismissal Without Prejudice of MEHC was entered by the court dismissing MEHC from the Cornerstone and Viola complaints. On December 5, 2003, the court entered Pretrial Order No. 1, which among other procedural matters, ordered the consolidation of the Cornerstone, Calle Gracey and Viola complaints and permitted plaintiffs to file an amended complaint in this matter. On January 20, 2004, plaintiffs filed In Re: Natural Gas Commodity Litigation as the amended complaint reasserting their previous allegations. On February 19, 2004, MidAmerican Energy filed a Motion to Dismiss and joined with several other defendants to file a joint Motion to Dismiss. The plaintiffs filed a response on May 19, 2004, contesting both Motions to Dismiss. On September 24, 2004, the pending Motions to Dismiss were denied. On October 14, 2004, the plaintiffs filed an amended consolidated class action complaint reasserting their previous allegations. On January 25, 2005, the plaintiffs filed their motion for class certification. MidAmerican Energy will continue to coordinate with the other defendants and vigorously defend the allegations against it.

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, LaPrairie Group Contractors (International) Ltd. (“LPG”), that MEHC’s 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, among others, CE Casecnan Ltd. and MEHC. On January 21, 2004, CE Casecnan Ltd. and LPG 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 distribution without at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan dividend distributions declared in 2004, totaling $15.9 million, was set aside by CE Casecnan in an unsecured CE Casecnan account and is shown as restricted cash and short-term investments and other current liabilities in the accompanying consolidated balance sheet included in “Item 8. Financial Statements and Supplementary Data” of this Form 10-K. The court is currently expected to rule on the first phase of the litigation before the end of the first quarter of 2005. The impact, if any, of this litigation on the Company cannot be determined at this time.

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 under the Mirant Agreement. In July 2003, Mirant filed for Chapter 11 bankruptcy protection and continued to perform under the Mirant Agreement post-bankruptcy. In October 2003, Mirant informed Kern River that it would not renew its letter of credit and Kern River drew on the letter of credit and held the proceeds thereof, $14.8 million, as cash collateral. Effective December 18, 2003, Mirant rejected the Mirant Agreement pursuant to procedures under the Bankruptcy Code and paid all post-petition amounts then due and owing under the Mirant Agreement through December 18, 2003. On January 13, 2004, Kern River filed a proof of claim with the bankruptcy court for an aggregate total amount of $210.2 million (the “Kern River Claim”), which Kern River believed was secured to the extent of the $14.8 million in proceeds received from the letter of credit and held as a cash security deposit. The claims underpinning the proof of claim arise from damages caused by Mirant’s rejection of the Mirant Agreement. On May 25, 2004, the bankruptcy court issued an order permitting Kern River to apply 100% of the $14.8 million cash security deposit to its claim for damages. On October 12, 2004, Mirant raised an objection to the Kern River Claim asserting, among other things, that Kern River had not included a discount adjustment or mitigation to the claim. On November 11, 2004, Kern River filed an amended proof of claim of $138.8 million, reflecting discounting, mitigation and other adjustments, and which excludes the $14.8 million already received by Kern River. Kern River can not determine at this time if it will collect any portion of the balance of the Kern River Claim or be able to remarket the rejected Mirant Agreement capacity.

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

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters.

Since March 14, 2000, MEHC’s equity securities have been owned by Berkshire Hathaway, Walter Scott, Jr. (together with certain of his family members and family trusts and corporations), 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 the Company’s consolidated financial statements and the related notes to those statements included in “Item 8. Financial Statements and Supplementary Data” and with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” appearing elsewhere in this Form 10-K. The selected financial data as of and for the years ended December 31, 2004, 2003, 2002 and 2001, and as of December 31, 2000 and for the period from March 14, 2000 through December 31, 2000, have been derived from the Company’s historical consolidated financial statements. The selected financial data from January 1, 2000 through March 13, 2000, have been derived from MEHC (Predecessor)’s historical consolidated financial statements.

																MEHC
																(Predecessor)
													March 14 2000			January 1, 2000
	Year Ended December 31,												through December 31,			through March 13,
	2004			2003			2002⁽¹⁾			2001⁽²⁾			2000⁽³⁾			2000⁽⁴⁾
	(Amounts in millions)
Statement of Operations Data:
Operating revenue	$	6,553.4		$	5,965.6		$	4,795.2		$	4,696.8		$	3,918.1		$	1,056.4
Income from continuing operations		537.8			442.7			397.4			148.4			84.1			51.4
Loss from discontinued operations, net of tax⁽⁵⁾		(367.6	)		(27.1	)		(17.4	)		(5.7	)		(2.8	)		(0.1	)
Net income	$	170.2		$	415.6		$	380.0		$	142.7		$	81.3		$	51.3

Balance Sheet Data:
Total assets	$	19,903.6		$	19,145.0		$	18,434.9		$	12,994.6		$	11,960.4			N/A
Parent company senior debt⁽⁶⁾		2,772.0			2,777.9			2,323.4			1,834.5			1,830.0			N/A
Parent company subordinated debt⁽⁶⁾		1,585.8			1,772.1			-			-			-			N/A
Company-obligated mandatory redeemable preferred securities of subsidiary trusts		-			-			2,063.4			788.2			786.5			N/A
Subsidiary and project debt⁽⁶⁾		6,304.9			6,674.6			7,077.1			4,754.8			3,398.7			N/A
Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts		-			-			-			100.0			100.0			N/A
Preferred securities of subsidiaries		89.5			92.1			93.3			121.2			145.7			N/A
Total stockholders’ equity	$	2,971.2		$	2,771.4		$	2,294.3		$	1,708.2		$	1,576.4			N/A

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

(2)	Reflects the Yorkshire Swap on September 21, 2001 and includes $15.2 million of after-tax income related to the sale of the Northern Electric electricity and gas supply business, the sale of the Telephone Flat Project, the sale of Western States Geothermal, the transfer of Bali Energy Ltd. shares, and the Teesside Power Limited (‘‘TPL’’) asset valuation impairment charge.

(3)	Reflects the Teton Transaction on March 14, 2000.

(4)	Includes $7.6 million of expenses related to the Teton Transaction.

(5)	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 and for the periods January 1, 2000 through March 13, 2000 and March 14, 2000 through December 31, 2000, are classified separately as discontinued operations.

(6)	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 Items 6 and 8 herein.

General

The Company’s operations are organized and managed on 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.

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 the United Kingdom, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.

The Company’s principal energy subsidiaries generate, transmit, store, distribute and supply energy. The Company’s electric and natural gas utility subsidiaries currently serve approximately 4.4 million electricity customers and approximately 680,000 natural gas customers. Its natural gas pipeline subsidiaries operate interstate natural gas transmission systems with approximately 18,300 miles of pipeline in operation and peak delivery capacity of 6.4 Bcf of natural gas per day. The Company has interests in 6,777 net owned MW of power generation facilities in operation and under construction, including 5,203 net owned MW in facilities that are part of the regulated return 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.

Executive Summary

The following significant events and changes, as discussed in more detail herein, highlight some factors that affect the comparability of our financial results, for the years ended December 31, 2004, 2003 and 2002, respectively:

·
On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project, effective immediately. Based on this decision, a non-cash, after-tax impairment charge of $340.3 million has been recorded to write-off the Mineral Assets.

·
In December 2004, MidAmerican Energy placed into service the second phase of its 327 MW natural gas-fired combined cycle generating plant. The plant is the first of three electric generating projects to be completed by MidAmerican Energy. MidAmerican Energy expects to invest approximately $1.1 billion in the two remaining projects through 2007. Both projects are currently under construction and $350.4 million of the $1.1 billion had been invested through December 31, 2004.

·
The Company made significant investments in its natural gas pipeline business by acquiring Kern River in March 2002 for $419.7 million, net of cash acquired, and Northern Natural Gas in August 2002 for $882.7 million, net of cash acquired, and completing the 2003 Expansion Project in May 2003 at a total cost of $1.2 billion. These pipelines serve major markets in the midwest and western United States.

·
HomeServices separately acquired 13 real estate companies throughout 2004, 2003 and 2002. Operating revenue has grown from $1.1 billion in 2002 to $1.8 billion in 2004.

·
CE Electric UK operates mainly in Great Britain and the majority of its transactions are in Pounds Sterling. The weighted average ratio of U.S. Dollars to Pounds Sterling was 1.84, 1.64 and 1.49 during each of the years ended December 31, 2004, 2003 and 2002, respectively, which continues to produce positive revenue and profit comparisons on a year over year basis.

·
Both Kern River and Northern Natural Gas have filed for rate increases with the FERC and have hearings scheduled in 2005. New rates for Northern Natural Gas’ May 2003 rate case went into effect on November 1, 2003, subject to refund. New rates for the Northern Natural Gas’ January 2004 and Kern River’s April 2004 rate cases each went into effect on November 1, 2004, subject to refund. Additionally, 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 will be reduced by 4% and 9%, respectively, in real terms, effective April 1, 2005.

·
CE Casecnan reached an arbitration settlement with the NIA effective during the fourth quarter of 2003. As part of the settlement, NIA paid CE Casecnan $17.7 million plus Philippines pesos of 39.9 million (approximately $0.7 million) and delivered a ROP $97.0 million 8.375% Note due in 2013. In exchange, CE Casecnan agreed to modify certain provisions of the 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. In January 2004, CE Casecnan exercised its right to put the note and received $99.2 million (representing par plus accrued interest) from the ROP.

·
On November 23, 2004, Northern Natural Gas sold its stipulated general, unsecured claim of $249.0 million against Enron Corp. (“Enron”) to a third party investor for $72.2 million and recorded the proceeds received as other income in 2004.

·
In the fourth quarter of 2004, CE Generation recorded a $16.8 million charge as a result of the partial impairment of the carrying value of the Power Resources project.

·
In February 2004, MEHC issued $250.0 million of 5.00% senior notes due February 15, 2014. The proceeds from these issuances were used to satisfy a demand made by MEHC’s affiliate, Salton Sea Funding Corporation (“Funding Corporation”), for the amount remaining on MEHC’s guarantee of Funding Corporation’s 7.475% Senior Secured Series F Bonds (“Series F Bonds”) and for other general corporate purposes. In October 2004, MidAmerican Energy issued $350.0 million of 4.65% medium-term notes due October 2014, which were used for general corporate purposes.

Results of Operations for the Year Ended December 31, 2004 and the Year Ended December 31, 2003

The following table summarizes net income for the years ended December 31(in millions):

		2004			2003
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income:
MidAmerican Energy	$	267.8		$	271.4
Kern River		142.6			133.7
Northern Natural Gas		218.0			127.3
CE Electric UK		325.9			288.7
CalEnergy Generation-Foreign		165.7			177.6
CalEnergy Generation-Domestic		3.1			2.1
HomeServices		111.9			90.0
Total reportable segments		1,235.0			1,090.8
Corporate/other		(435.8	)		(232.9	)
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		799.2			857.9
Income tax expense		265.0			270.3
Minority interest and preferred dividends of subsidiaries		13.3			183.2
Income from continuing operations before equity income		520.9			404.4
Equity income		16.9			38.3
Income from continuing operations		537.8			442.7
Loss from discontinued operations, net of tax benefits		(367.6	)		(27.1	)
Net income available to common and preferred stockholders	$	170.2		$	415.6

The $367.6 million loss from discontinued operations, net of tax benefits, for the year ended December 31, 2004 included a $340.3 million non-cash impairment charge recognized in connection with ceasing operations of the Company’s Zinc Recovery Project and a $27.1 million loss from operations, net of tax, of the Zinc Recovery Project.

Income from continuing operations for the year ended December 31, 2004, increased $95.1 million, or 21.5%, to $537.8 million compared with $442.7 million for the same period in 2003.

Equity income for the year ended December 31, 2004, decreased $21.4 million to $16.9 million compared with $38.3 million for the same period in 2003. CE Generation recorded a $16.8 million charge as a result of the partial impairment of the carrying value of the Power Resources project. Additionally, HomeServices’ mortgage joint ventures had lower income due to lower refinancing activity.

Minority interest and preferred dividends for the year ended December 31, 2004, decreased $169.9 million to $13.3 million from $183.2 million for the same period in 2003. The decrease was due to the Company’s adoption, as of October 1, 2003, of FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities” (“FIN 46R”) related to certain finance subsidiaries. The adoption required the deconsolidation of certain finance subsidiaries, which resulted in the amounts previously classified as mandatorily redeemable preferred securities of subsidiary trusts being reclassified as parent company subordinated debt in the Company’s consolidated balance sheet at December 31, 2003. The adoption also required that amounts previously recorded in minority interest and preferred dividends of subsidiaries be recorded as interest expense in the Company’s consolidated statements of operations, prospectively. In accordance with the requirements of FIN 46R, no amounts prior to adoption, on October 1, 2003, have been reclassified. The amount remaining in minority interest and preferred dividends of subsidiaries related to these mandatorily redeemable preferred securities of subsidiary trusts for the nine-month period ended September 30, 2003, was $170.2 million.

Income tax expense for the year ended December 31, 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 the years ended December 31, 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, and the settlement by CE Electric UK of various positions with the Inland Revenue department and a change in the State of Iowa’s income tax laws in 2004.

Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income decreased $58.7 million, or 6.8%, to $799.2 million in 2004 from $857.9 million in 2003. The decrease was due to the following:

Reportable Segments

Kern River's pre-tax earnings were $8.9 million higher due to the completion of the 2003 Expansion Project in May 2003, partially offset by lower capitalized interest in connection with completing the expansion. In 2004, Kern River collected $14.8 million on its claim for damages against Mirant for the rejection by Mirant of its firm gas transportation contract. The income was largely offset by revenue lost related to the rejection of the agreement.

·	Northern Natural Gas' pre-tax earnings were $90.7 million higher due to a $72.2 million pre-tax gain on the sale of the Enron Note Receivable and improved results associated with the May 2003 rate case which resulted in higher rates commencing November 1, 2003.

CE Electric UK's pre-tax earnings were $37.2 million higher primarily from the approximately $34.0 million favorable earnings impact of the continued weakness of the U.S. dollar relative to the British pound, partially offset by the $8.9 million gain from the sale of a local operational and dispatch facility at Northern Electric in 2003.

CalEnergy Generation-Foreign's pre-tax earnings were $11.9 million lower in 2004 compared to 2003. In 2003, CE Casecnan recorded $31.9 million of income in connection with the settlement of its arbitration with the NIA. That gain was partially offset by the settlement of various disputes which the Leyte Projects had with PNOC-EDC, which resulted in the reversal of accrued revenue totaling $11.3 million. In 2004, CE Casecnan had lower revenue as a result of its contract arbitration settlement, which was fully offset by higher revenue at the Leyte Projects due to price indices and lower interest expense on the repayment of project debt. Also in 2004, CalEnergy Generation-Foreign earned higher interest income on affiliate loans of $8.7 million.

·	Pre-tax earnings at HomeServices were $21.9 million higher due to higher average home sales prices and acquisitions not included in the comparable 2003 period.

Corporate

The Company’s adoption of FIN 46R, as previously described, required that amounts previously recorded in minority interest and preferred dividends of subsidiaries be recorded as interest expense in the Company’s consolidated statements of operations prospectively. As a result, the charges for interest expense related to securities of the Company’s finance subsidiaries increased by $147.1 million to $196.9 million in 2004 from $49.8 million in 2003.

·	During June 2003, the Company sold its investment in Williams Cumulative Convertible Preferred Stock. As a result, 2003 pre-tax earnings included $32.6 million from the gain on the sale and dividend income.

·	The Company's corporate interest expense increased $11.5 million primarily as a result of the issuance of the $250.0 million of 5.00% senior notes in February 2004.

Revenue

Operating revenue for the year ended December 31, 2004 increased $587.8 million or 9.9% to $6,553.4 million from $5,965.6 million for the same period in 2003. The following table summarizes operating revenue by segment for the years ended December 31 (in millions):

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

MidAmerican Energy’s operating revenue for the year ended December 31, 2004, increased $101.5 million, or 3.9%, to $2,701.7 million. Regulated and non-regulated natural gas revenue increased $53.8 million, or 4.8%, to $1,166.5 million mainly due to higher prices for natural gas purchased for regulated customers, which is passed directly to the customer, and regulated wholesale volumes. Average natural gas prices increased 7.4% from 2003 to 2004. These price increases were partially offset by lower regulated retail and non-regulated volumes. Regulated and non-regulated electric revenue increased $49.8 million, or 3.4%, to $1,518.9 million mainly due to higher regulated retail and non-regulated volumes as well as prices of wholesale sales. These increases were partially offset by lower regulated wholesale volumes and regulated retail prices.

Operating revenue at Kern River and Northern Natural Gas is principally derived by providing firm or interruptible transportation services under long-term gas transportation service agreements. Northern Natural Gas also derives part of its revenue from storing gas. Kern River’s operating revenue for the year ended December 31, 2004, increased $55.9 million, or 21.5%, to $316.1 million primarily due to the transportation fees earned in connection with the 2003 Expansion Project, which began operations May 1, 2003. Northern Natural Gas’ operating revenue, which reflects the impact of the new rates beginning November 1, 2004 and 2003, and higher gas and liquid sales, increased $57.9 million, or 11.9%, to $544.8 million for the year ended December 31, 2004.

CE Electric UK’s operating revenue for the year ended December 31, 2004, increased $106.4 million, or 12.8%, to $936.4 million primarily as a result of the weaker U.S. dollar. Additionally, CE Electric UK experienced increased revenue at its contracting business.

Operating revenue for CalEnergy Generation-Foreign for the year ended December 31, 2004, decreased $19.0 million, or 5.8%, to $307.4 million primarily due to lower water delivery fees in connection with the NIA arbitration settlement at CE Casecnan effective in the fourth quarter of 2003, partially offset by higher energy fees due to increased generation on higher water flows in 2004.

HomeServices’ operating revenue for the year ended December 31, 2004, consisting mainly of commission revenue from real estate brokerage transactions, increased $279.8 million, or 18.9%, to $1,756.4 million. The increase is due primarily to growth at existing businesses of $154.7 million due primarily to higher average home sales prices and acquisitions not included in the comparable 2003 period totaling $125.1 million. During the year ended December 31, 2004, HomeServices participated in $59.8 billion of transactions, an increase of $11.2 billion from 2003. About 24% of the increase came from the six acquisitions made during the year.

Costs and expenses

Cost of sales for the year ended December 31, 2004, increased $351.4 million, or 14.6%, to $2,751.9 million from $2,400.5 million for the same period in 2003. HomeServices’ cost of sales, consisting primarily of commissions on real estate brokered transactions, increased $211.8 million due to higher commission expense on incremental sales at existing business units and acquisitions not included in the comparable 2003 period. MidAmerican Energy’s costs of sales increased $87.4 million due mainly to an increase in the per unit cost of natural gas, higher regulated wholesale natural gas, regulated retail electric and non-regulated electric volumes, partially offset by lower regulated retail and non-regulated natural gas volumes. Northern Natural Gas’ cost of sales increased $18.9 million due to higher gas and liquid sales. CE Electric UK’s cost of sales increased $16.7 million mainly due to increased activity at its contracting business 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 the year ended December 31, 2004, increased $125.6 million, or 8.3%, to $1,637.9 million from $1,512.3 million for the same period in 2003. HomeServices’ operating expenses, consisting mainly of compensation, marketing and other administrative costs, increased $44.8 million due mainly to acquisitions not included in the comparable 2003 period. MidAmerican Energy’s operating expenses increased $40.3 million due mainly to higher generation maintenance costs, Quad Cities Station expenses, and transmission expenses. CE Electric UK’s operating expenses increased $39.3 million, mainly 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. Kern River’s operating expenses increased $16.4 million due to the commencement of operations of the 2003 Expansion Project. CalEnergy Generation-Foreign’s operating expenses decreased $12.5 million mainly due to lower legal and other costs in 2004.

Depreciation and amortization for the year ended December 31, 2004, increased $35.3 million to $638.2 million from $602.9 million for the same period in 2003. Kern River’s expense increased $16.5 million due to the completion of the 2003 Expansion Project. Northern Natural Gas’ expense increased $15.2 million due to higher depreciation rates consistent with the filed rate case. CE Electric UK’s expense increased $12.7 million primarily due to the weaker U.S. dollar. Partially offsetting these increases was a decrease in MidAmerican Energy’s expense of $14.6 million due primarily to a decrease in regulatory expense related to its revenue sharing arrangements.

Other income and expense

Interest expense for the year ended December 31, 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 as interest expense in the accompanying consolidated statement of operations, prospectively. For the year ended December 31, 2004 and the three-month period ended December 31, 2003, the Company has 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 have been 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.

Capitalized interest for the year ended December 31, 2004, decreased $10.5 million to $20.0 million from $30.5 million for the same period in 2003. The decrease was mainly due to the discontinuance of capitalizing interest on Kern River’s 2003 Expansion Project, partially offset by increased construction activity at MidAmerican Energy’s generation projects.

Interest and dividend income for the year ended December 31, 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 the year ended December 31, 2004, increased $31.6 million to $128.2 million from $96.6 million for the same period in 2003. 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 the year ended December 31, 2004, decreased $6.2 million due primarily to the completion of Kern River’s expansion in 2003.

Results of Operations for the Year Ended December 31, 2003 and the Year Ended December 31, 2002

The following table summarizes net income for the years ended December 31(in millions):

		2003			2002
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income:
MidAmerican Energy	$	271.4		$	238.8
Kern River		133.7			60.7
Northern Natural Gas		127.3			42.9
CE Electric UK		288.7			266.8
CalEnergy Generation-Foreign		177.6			147.9
CalEnergy Generation-Domestic		2.1			(1.2	)
HomeServices		90.0			61.2
Total reportable segments		1,090.8			817.1
Corporate/other		(232.9	)		(185.4	)
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		857.9			631.7
Income tax expense		270.3			111.3
Minority interest and preferred dividends of subsidiaries		183.2			163.5
Income from continuing operations before equity income		404.4			356.9
Equity income		38.3			40.5
Income from continuing operations		442.7			397.4
Loss from discontinued operations, net of tax benefits		(27.1	)		(17.4	)
Net income available to common and preferred stockholders	$	415.6		$	380.0

The loss from discontinued operations, net of tax benefits, for the year ended December 31, 2003, was $27.1 million as compared to $17.4 million for 2002 and consists of losses from the operation of the Company’s Zinc Recovery Project.

Income from continuing operations for the year ended December 31, 2003, increased $45.3 million, or 11.4%, to $442.7 million compared with $397.4 million for the same period in 2002.

Equity income for the year ended December 31, 2003, decreased $2.2 million to $38.3 million compared with $40.5 million for the same period in 2003. Equity income from non-regulated generation equity investments decreased $16.6 million to $14.8 million from $31.4 million in 2002 mainly due to the expiration of a contract at the Power Resources project and a charge associated with an equity investment. Equity income from HomeServices for the year ended December 31, 2003 increased $14.8 million to $23.6 million primarily due to increased refinancing activity at mortgage joint ventures.

Minority interest and preferred dividends for the year ended December 31, 2003, increased $19.7 million to $183.2 million from $163.5 million for the same period in 2002. As previously described, the Company was required to adopt, as of October 1, 2003, FIN 46R related to certain finance subsidiaries. The adoption required that amounts previously recorded in minority interest and preferred dividends of subsidiaries be recorded as interest expense in the Company’s consolidated statements of operations prospectively. In accordance with the requirements of FIN 46R, no amounts prior to adoption, on October 1, 2003, have been reclassified. The amount remaining in minority interest and preferred dividends of subsidiaries related to these securities increased $22.5 million to $170.2 million for the nine-month period ended September 30, 2003, from $147.7 million for the year ended December 31, 2002. Mandatorily redeemable preferred securities of subsidiary trusts were issued in 2002 to finance the acquisitions of both Kern River and Northern Natural Gas.

Income tax expense for the year ended December 31, 2003, increased $159.0 million to $270.3 million from $111.3 million for the same period in 2002. The effective tax rate was 31.5% and 17.6% for the years ended December 31, 2003 and 2002, respectively. The increase in the effective tax rate was primarily due to increased tax expense on foreign income including the incremental tax expense of $24.4 million in connection with the CE Casecnan NIA arbitration settlement proceeds. The 2002 effective tax rate was unusually low as the Company recognized tax benefits of $35.7 million in connection with the execution of the TPL restructuring agreement at CE Electric UK.

Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income increased $226.2 million, or 35.8%, to $857.9 million in 2003 from $631.7 million in 2002. The increase was due to the following:

Reportable Segments

Pre-tax earnings at MidAmerican Energy were higher by $32.6 million. The reportable segment earned higher regulated Iowa electric income as it benefited from the first phase of the Greater Des Moines Energy Center beginning operation in May 2003, higher equity funds used during the construction of its electric generation projects, and certain non-recurring items, including lower fuel costs resulting from a contract restructuring and the settlement of a bankruptcy claim.

Kern River, acquired in March 2002, and Northern Natural Gas, acquired in August 2002, had higher pre-tax earnings of $73.0 million and $84.4 million, respectively, due mainly to the inclusion of the acquisitions for a full-year of operations in the Company’s consolidated results and the completion of Kern River’s 2003 Expansion Project.

CE Electric UK's pre-tax earnings were higher by $21.9 million. Approximately $20.0 million of the increase resulted from higher distribution revenue at Yorkshire Electricity, $18.5 million was due to the earnings benefit of the continued weakness of the U.S. dollar relative to the British pound, $11.3 million related to lower costs primarily achieved from economies of scale with Northern Electric and Yorkshire Electricity, $14.4 million was a result of the gain and lower interest costs associated with a bond redemption, $8.9 million related to the gain on sale of a local operational and dispatch facility at Northern Electric, and $7.0 million for rebates received from the National Grid Company. These increases were partially offset by the sale of several of its north sea, natural gas assets resulting in a pre-tax gain of $54.3 million.

Pre-tax earnings at CalEnergy Generation-Foreign were higher by $29.7 million. In 2003, CE Casecnan recorded $31.9 million of other income in connection with the settlement of its arbitration with the NIA. The 2003 gain was partially offset by the settlement of various disputes which the Leyte Projects had with PNOC-EDC, which resulted in the reversal of accrued revenue totaling $11.3 million. The other significant difference in 2003 was the decrease in financial expense of $10.6 million due to repayment of debt and lower variable interest rates.

·	HomeServices' pre-tax earnings were higher by $28.8 million due to acquisitions made throughout 2002 and 2003 and due to growth from higher home prices and higher mortgage refinancing activity at existing companies.

Corporate

The Company’s adoption of FIN 46R, as previously described, required that amounts previously recorded in minority interest and preferred dividends of subsidiaries be recorded as interest expense in the Company’s consolidated statements of operations prospectively. The charge to interest expense related to securities of the Company’s finance subsidiaries was $49.8 million in 2003 and $ - million in 2002.

Revenue

Operating revenue for the year ended December 31, 2003 increased $1,170.4 million or 24.4% to $5,965.6 million from $4,795.2 million for the same period in 2002. The following table summarizes operating revenue by segment for the years ended December 31 (in millions):

	Year Ended December 31,
		2003			2002
Operating revenue:
MidAmerican Energy	$	2,600.2		$	2,240.9
Kern River		260.2			127.3
Northern Natural Gas		486.9			178.1
CE Electric UK		830.0			795.4
CalEnergy Generation-Foreign		326.4			326.3
CalEnergy Generation-Domestic		45.2			38.5
HomeServices		1,476.6			1,138.3
Total reportable segments		6,025.5			4,844.8
Corporate/other		(59.9	)		(49.6	)
Total operating revenue	$	5,965.6		$	4,795.2

MidAmerican Energy’s operating revenue for the year ended December 31, 2003, increased $359.3 million, or 16.0%, to $2,600.2 million. MidAmerican Energy’s regulated and non-regulated gas revenue for the year ended December 31, 2003 increased $308.4 million to $1,112.7 million from $804.3 million in 2002 mainly due to higher prices for gas purchased for regulated customers which is passed directly to the customer. Average gas prices increased 59.9% or $2.24 per Dth from 2002 to 2003. Regulated electric revenue for the year ended December 31, 2003 increased $44.6 million to $1,398.0 million from $1,353.4 million for the same period in 2002 mainly due to higher prices of wholesale sales during 2003.

Operating revenue at both pipelines is principally derived by providing firm or interruptible transportation services under long-term gas transportation service agreements. Northern Natural Gas also derives part of its revenue from storing gas. Kern River’s operating revenue for the year ended December 31, 2003, increased $132.9 million to $260.2 million. The increase was primarily due to the transportation fees earned in connection with the 2003 Expansion Project which began operations May 1, 2003, and to a lesser degree, the inclusion of its operations for all of 2003. Northern Natural Gas’ operating revenue for the year ended December 31, 2003, increased $308.8 million to $486.9 million. Northern Natural Gas was acquired on August 16, 2002. The increase in its operating revenue relates to the timing of that acquisition and inclusion of its operations for all of 2003.

CE Electric UK’s operating revenue for the year ended December 31, 2004, increased $34.6 million, or 4.4%, to $830.0 million. The increase was a result of the weaker U.S. dollar, higher distribution revenue and higher revenue at its contracting business. This was partially offset by lower revenue caused by the sale of CE Gas assets in 2002.

HomeServices’ operating revenue for the year ended December 31, 2003, consisting mainly of commission revenue from real estate brokerage transactions, increased $338.3 million, or 29.7%, to $1,476.6 million. The increase was due to acquisitions made throughout 2002 and 2003 and $91.3 million due to growth at existing companies. During the year ended December 31, 2003, HomeServices participated in $48.6 billion of transactions, an increase of $11.7 billion from 2002. About 23% of the increase came from the four acquisitions made during the year.

Costs and expenses

Cost of sales for the year ended December 31, 2003 increased $556.5 million, or 30.2%, to $2,400.5 million from $1,844.0 million for the same period in 2002. MidAmerican Energy’s cost of sales for the year ended December 31, 2003 increased $345.6 million, or 34.9%, to $1,334.5 million from $988.9 million for the same period in 2002. MidAmerican Energy’s regulated and non-regulated gas cost of sales for the year ended December 31, 2003 increased $291.1 million to $878.1 million from $587.0 million in 2002 mainly due to the increase in per unit cost of gas discussed in operating revenue. Electric cost of sales increased $51.0 million in 2003 primarily due to the reclassification of costs for energy purchased under the Cooper Nuclear Station restructured contract between MidAmerican Energy and the Nebraska Public Power District which expired in December 2004. Prior to August 1, 2002, the date of the restructuring, only fuel costs for energy purchased from Cooper Nuclear Station were classified as a cost of sales. Consistent with the restructured contract, other costs under the contract are classified as operating expenses. Following the restructuring, all costs for energy and capacity purchased under the contract were included in cost of sales consistent with the new power purchase contract. Operating expenses decreased accordingly.

HomeServices’ cost of sales, consisting primarily of commissions on real estate brokerage transactions, increased $235.6 million for the year ended December 31, 2003, or 30.7%, to $1,003.2 million from $767.6 million for the same period in 2002. Cost of sales increased $106.7 million due to acquisitions made during 2002 and 2003. The remainder of HomeServices’ increase was due to growth of existing companies totaling $128.9 million.

Operating expenses for the year ended December 31, 2003 increased $209.5 million, or 16.1%, to $1,512.3 million from $1,302.8 million for the same period in 2002. An increase of $146.6 million was due to Northern Natural Gas, which was owned for the entire period in 2003. Increased operating expenses at HomeServices were $78.8 million, primarily due to the impact of acquisitions and increased compensation expenses. These increases were partially offset by lower operating expenses at CE Electric UK of $39.6 million, mainly due to the sale of the retail business in 2002 and a gain on the sale of a local operational dispatch facility in 2003, and lower operating expenses at MidAmerican Energy of $19.5 million primarily due to the restructuring of the Cooper contract.

Depreciation and amortization for the year ended December 31, 2003 increased $72.8 million, or 13.7%, to $602.9 million from $530.1 million for the same period in 2002. An increase of $34.6 million was due to Northern Natural Gas, which was owned for the entire period in 2003. Increased depreciation at Kern River was $19.6 million mainly due to the completion of the 2003 Expansion Project and the inclusion of Kern River’s operations for the entire period. Increased depreciation of $11.6 million at MidAmerican Energy due to higher utility plant depreciation and increased depreciation of $8.2 million at CE Electric UK due to a weaker U.S. dollar and an increased asset base, partially offset by the CE Gas asset sale in 2002.

In 2002, CE Gas executed the sale of several of its assets and recorded a pre-tax gain of $54.3 million, which included a write off of non-deductible goodwill of $49.6 million. 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 asset sales.

Other Income and Expense

Interest expense for the year ended December 31, 2003 increased $128.9 million to $761.0 million from $632.1 million for the same period in 2002. The increase was mainly due to interest on parent company subordinated debt which was $49.8 million for the quarter and year ended December 31, 2003. This amount represents the interest recorded on the parent company subordinated debt for the period from October 1, 2003, the date the Company adopted FIN 46R, through December 31, 2003. Prior to the adoption of FIN 46R, the parent company subordinated debt was classified as company-obligated mandatorily redeemable preferred securities of subsidiary trusts. Costs associated with those instruments, prior to the adoption of FIN 46R, were classified as minority interest and preferred dividends of subsidiaries in the accompanying consolidated statements of operations. The remaining $79.1 million increase resulted from additional interest expense totaling $38.9 million on MEHC’s debt issuances of $700.0 million in October 2002 and $450.0 million in May 2003, increased interest expense of $32.5 million at Northern Natural Gas primarily due to a full year of ownership and increased interest expense at Kern River of $32.2 million due to additional borrowings related to the 2003 Expansion Project and a full year of ownership. The increases were partially offset by decreased interest, totaling $27.9 million, due to the combination of the June 2003 redemption of the Yorkshire Electricity securities, reductions in CalEnergy Generation-Foreign project debt, MEHC’s revolving credit facility and the retirement of MEHC’s 6.96% Senior Notes.

Capitalized interest for the year ended December 31, 2003 increased $7.1 million to $30.5 million. The increase was mainly due to Kern River’s 2003 Expansion Project and increased construction activity at MidAmerican Energy’s generation projects.

Interest and dividend income for the year ended December 31, 2003 decreased $8.1 million to $47.9 million from $56.0 million for the same period in 2002. The decrease was primarily due to lower income at CE Electric UK of $9.9 million due to lower cash balances partially offset by higher dividend income on the investment in Williams Cumulative Convertible Preferred Stock totaling $4.7 million and interest earned on higher corporate cash balances available during 2003.

Other income for the year ended December 31, 2003, increased $56.4 million to $96.6 million from $40.2 million for the same period in 2003. 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 the year ended December 31, 2003, increased $7.3 million due primarily to the construction of Kern River’s expansion in 2003.

Other expense for the year ended December 31, 2003, decreased $22.7 million to $5.9 million from $28.6 million for the same period in 2002. In 2002, MidAmerican Energy recorded an impairment of its investment in airplane leases and other non-regulated investments of $21.7 million.

Liquidity and Capital Resources

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 were $960.9 million at December 31, 2004, compared to $660.2 million at December 31, 2003. 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 $164.5 million and $119.5 million at December 31, 2004 and 2003, respectively. The restricted cash balance for both periods is comprised primarily of amounts deposited in restricted accounts which are reserved for the service of debt obligations, customer deposits held in escrow, custody deposits and unpaid dividends declared obligations.

Cash Flows from Operating Activities

The Company generated cash flows from operations of $1,424.6 million for the year ended December 31, 2004, compared with $1,217.9 million for the same period in 2003. The increase was mainly due to greater income from continuing operations and a tax refund as a result of a 2003 net operating loss from accelerated depreciation. Also contributing to the net increase in cash flows from operations were changes in working capital, partially offset by lower distributions from equity investments.

Cash Flows from Investing Activities

Cash flows used in investing activities for the years ended December 31, 2004 and 2003 were $1,029.7 million and $1,003.2 million, respectively. Capital expenditures, construction and other development costs for the years ended December 31, 2004 and 2003 were $1,179.4 million and $1,219.4 million, respectively. In addition to the capital expenditures, contributing to the increase of cash flows used in investing activities was $288.8 million of proceeds from the sale of convertible preferred securities in 2003, partially offset by the receipt of the proceeds of the put of the ROP Note, and sale of the Enron Note Receivable claim, as described below.

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.

Capital Expenditures, Construction and Other Development Costs

Capital expenditures, construction and other development costs were $1,310.3 for the year ended December 31, 2004, compared with $1,179.8 million for the same period in 2003. The following table summarizes the expenditures by business segment (in millions):

	Year Ended December 31,
		2004		2003
Capital expenditures:
MidAmerican Energy	$	633.8	$	346.5
Kern River		26.9		433.1
Northern Natural Gas		138.8		104.4
CE Electric UK		334.5		301.9
CalEnergy Generation-Foreign		4.6		8.5
CalEnergy Generation-Domestic		1.3		6.6
HomeServices		20.8		18.3
Segment capital expenditures		1,160.7		1,219.3
Corporate/other		18.7		0.1
Total capital expenditures	$	1,179.4	$	1,219.4

Forecasted capital expenditures, construction and other development costs for fiscal 2005 are approximately $1.3 billion. 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 mainly of recurring expenditures, were $778.3 million for the year ended December 31, 2004. Construction and other development costs were $401.0 million for the year ended December 31, 2004. These costs consist mainly of expenditures for large scale, generation projects as follows:

MidAmerican Energy

MidAmerican Energy has obtained regulatory approval to include the Iowa portion of the actual costs of the generation projects in its Iowa rate base as long as actual costs do not exceed the agreed caps that MidAmerican Energy has deemed to be reasonable. If the caps are exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures above the caps, subject to regulatory review. Wholesale sales may also be made from the projects to the extent the power is not immediately needed for regulated retail service. MidAmerican Energy expects to invest approximately $1.1 billion in the CBEC Unit 4 and wind generation projects currently under construction, of which $350.4 million has been invested through December 31, 2004.

MidAmerican Energy recently completed work on its Greater Des Moines Energy Center, a natural gas-fired, combined cycle unit located near Pleasant Hill, Iowa. Construction of the plant was completed in two phases. Commercial operation of the simple cycle mode began on May 5, 2003, and continued through most of 2004, providing 327 MW of accredited capacity in the summer of 2004. Commercial operation of the combined cycle mode began on December 16, 2004. The additional accredited capacity from completion of the second phase is expected to be 190 MW. MidAmerican Energy expects the total cost of the Greater Des Moines Energy Center to be under the $357.0 million cost cap established by the IUB.

MidAmerican Energy is currently constructing the CBEC Unit 4, a 790 MW (based on expected accreditation) super-critical-temperature, low-sulfur coal-fired 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 ownership interest is 60.67%, equating to 479 MW of output. MidAmerican Energy expects its share of the estimated cost of the project, including transmission facilities, to be approximately $737.0 million, excluding allowance for funds used during construction. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. On February 12, 2003, MidAmerican Energy executed a contract with Mitsui for engineering, procurement and construction of the plant. On September 9, 2003, MidAmerican Energy began construction of the plant, which it expects to be completed in the summer of 2007. On December 29, 2004, MidAmerican Energy received an order from the IUB approving construction of the associated transmission facilities and is proceeding with construction.

The second electric generating project currently under construction consists of wind power facilities located at two sites in north central Iowa totaling 310 MW based on the nameplate rating. 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 projected accredited capacity for these wind power facilities is approximately 53 MW. MidAmerican Energy will own and operate these facilities, which are expected to cost approximately $323.0 million, including transmission facilities and excluding the allowance for funds using during construction. As of December 31, 2004, wind turbines totaling 160.5 MW at one of the sites were completed and in service. Completion of the remaining turbines is expected by the middle of 2005. On January 31, 2005, the IUB approved ratemaking principles related to expanding the wind power project. An additional 50 MW of capacity, based on nameplate rating, is expected to be constructed at the sites in 2005 at an estimated cost of $63.0 million.

HomeServices’ Acquisitions

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. These purchases were financed using HomeServices’ cash balances. 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. Additionally in 2004, HomeServices paid an earnout of $6.0 million based on 2004 financial performance measures. These purchases were financed using HomeServices’ cash balances and revolving credit facility.

Cash Flows from Financing Activities

Cash flows used in financing activities for the year ended December 31, 2004 were $122.8 million. During 2004, the Company used cash for financing activities, totaling $747.9 million, primarily for repayments of subsidiary and parent company obligations, including $136.4 million of cash flows from discontinued operations, and generated cash from financing activities, totaling $625.1 million, from the issuance of subsidiary, project and parent company debt. Cash flows used in financing activities for the year ended December 31, 2003 were $426.3 million. During 2003, the Company used cash for financing activities, totaling $2,033.2 million, primarily for repayments of subsidiary obligations and parent company debt and the retirement of preferred securities of subsidiary trusts, and generated cash from financing activities, totaling $1,606.9 million, from the issuance of subsidiary, project and parent company debt.

Recent Debt Issuances, Redemptions and Stock Transactions

On February 12, 2004, MEHC completed the sale of $250 million in aggregate principal amount of its 5.00% senior notes due February 15, 2014. The proceeds were used to satisfy a demand made by its affiliate, Funding Corporation, for $136.4 million, the amount remaining on MEHC’s guarantee of Funding Corporation’s Series F Bonds, and for other general corporate purposes.

On March 1, 2004, Funding Corporation completed the redemption of an aggregate principal amount of $136.4 million of its Series F Bonds, pro rata, at a redemption price of 100% of such aggregate outstanding principal amount, plus accrued interest to the date of redemption. A demand was also made on MEHC for the full amount remaining on MEHC’s guarantee of the Series F Bonds in order to fund the redemption. MEHC made the requisite payment and, as a result, it has no further liability with respect to its guarantee. The payment was included in cash flows from discontinued operations.

On October 1, 2004, MidAmerican Energy issued $350.0 million of 4.65% medium-term notes due October 1, 2014. The proceeds were used for general corporate purposes.

In 2004, the Company made the required $100.0 million payment on its 11.00% parent company subordinated debt. The payments on subsidiary and project debt made in 2004 consisted of the maturity of CE Electric UK’s 6.853% senior notes, totaling $117.1 million, and regularly scheduled principal payments on project term loans.

On January 6, 2004, the Company purchased a portion of the shares of common stock owned by the Company’s chairman and chief executive officer, for an aggregate purchase price of $20.0 million.

Current Maturities of Long-Term Debt

The Company’s current portion of long-term debt increased $644.7 million to $1,145.6 million at December 31, 2004, from $500.9 million at December 31, 2003, due mainly to $260.0 million of 7.23% parent company senior notes becoming due in the third quarter of 2005, and, 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 has included the entire principal amount of these securities in its current portion of long-term debt in the accompanying consolidated balance sheet. The Company plans to use existing cash and future debt issuances to repay these obligations.

Restricted Cash and Short-Term Investments

During the year ended December 31, 2004, CE Casecnan increased its restricted cash related to obligations for debt service and unpaid dividends declared. Additionally, Northern Natural Gas increased its restricted cash related to custody deposits.

Discontinued Operations - Zinc Recovery Project and Mineral Assets

The Zinc Recovery Project began limited production during December 2002 and continued limited production until September 10, 2004. Efforts to increase production had continued since the Zinc Recovery Project was place in service with an emphasis on process modification. Management had been assessing the long-term economic viability of the Zinc Recovery Project in light of continuing cash flow deficits and operating losses and the efforts to increase production, and had continued to evaluate the expected impact of the planned improvements to the extraction process during the third quarter of 2004. Furthermore, management had been exploring other operating alternatives, such as establishing strategic partnerships and consideration of ceasing operations of the Zinc Recovery Project.

On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project, effective immediately. Based on this decision, a non-cash, after-tax impairment charge of $340.3 million has been recorded to write-off the Mineral Assets.

In connection with ceasing operations, the Zinc Recovery Project’s assets are being dismantled and sold and certain employees of the operator of the Zinc Recovery Project were paid one-time termination benefits. 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. The Company expects to make additional cash expenditures of pre-tax disposal costs and property taxes of approximately $1.6 million. Substantially all of such costs are expected to relate to disposal activities, and a portion of the disposal costs is expected to be offset by proceeds from sales of the Zinc Recovery Project’s assets. These costs are recognized in the period in which the related liability is incurred. Salvage proceeds will be recognized in the period earned. Implementation of a disposal plan began in September 2004 and will continue in 2005. The Company also expects to receive approximately $55 million in future tax benefits.

The operating losses from discontinued operations before income taxes during the years ended December 31, 2004, 2003 and 2002 were $42.7 million, $46.4 million and $29.1 million, respectively.

Credit Ratings Risks

Debt and preferred securities of the Company 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, the Company does 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 wholesale marketing and trading activities, MidAmerican Energy must meet credit quality standards as required by counterparties. MidAmerican Energy has energy trading agreements that, in accordance with industry practice, 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 marketing and trading activities. As of December 31, 2004, MidAmerican Energy’s estimated potential collateral requirements totaled approximately $151.0 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, entered into 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 the $281.1 million of the 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 7.345%. The estimated fair value of these swap agreements at December 31, 2004 was $96.1 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 December 31, 2004, 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 approximately $44.8 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, preferred equity securities, operating leases and power and fuel purchase contracts. Other obligations arise from unused lines of credit and letters of credit. Material obligations as of December 31, 2004 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	$	3,032.0	$	260.0	$	550.0	$	1,000.0	$	1,222.0
Parent company subordinated debt		1,774.4		188.5		468.0		468.0		649.9
Subsidiary and project debt		7,190.4		885.6		695.3		844.3		4,765.2
Preferred securities of subsidiaries		89.5		-		-		-		89.5
Interest payments on long-term debt⁽¹⁾		7,588.5		811.9		1,417.8		1,056.7		4,302.1
Coal, electricity and natural gas contract commitments (2)		668.8		173.0		255.3		122.2		118.3
Operating leases ⁽²⁾		375.0		70.4		121.0		78.9		104.7
Deferred costs on construction contracts ⁽³⁾		152.3		-		152.3		-		-
Total contractual cash obligations	$	20,870.9	$	2,389.4	$	3,659.7	$	3,570.1	$	11,251.7

	Commitment Expiration per Period
				<		2-3		4-5		>5
Total				1 Year		Years		Years		Years
Other Commercial Commitments:
Unused parent company revolving lines of credit	$	30.0	$	-	$	30.0	$	-	$	-
Parent company letters of credit		71.1		71.1		-		-		-
Unused subsidiary lines of credit		144.9		144.9		-		-		-
Total other commercial commitments	$	246.0	$	216.0	$	30.0	$	-	$	-

______________

(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 Mitsui under its engineering, procurement and construction contract to build the CBEC Unit 4, which is expected to be complete in the summer of 2007.

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.

·	Construction expenditures (see Note 6)

·	Asset retirement obligations (see Note 10)

·	Debt service reserve guarantees (see Note 14)

·	Nuclear decommissioning costs (see Note 21)

·	Residual guarantees on operating leases (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, 2004, the Company’s investments which are accounted for under the equity method had $861.3 million of debt and $40.2 million in outstanding letters of credit. As of December 31, 2004, the Company’s pro-rata share of such debt and outstanding letters of credit, which is all non-recourse to MEHC, was $430.3 million and $20.1 million, respectively.

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 2003, the FASB issued FIN 46R, which served to clarify guidance in FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51” (“FIN 46”). 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 the amounts previously classified as mandatorily redeemable preferred securities of subsidiary trusts, in the amount of $1.9 billion, being reclassified to parent company subordinated debt in the accompanying consolidated balance sheets. In addition, amounts previously recorded as minority interest and preferred dividends of subsidiaries are now recorded as interest expense in the accompanying consolidated statements of operations prospectively. For the year ended December 31, 2004, and the three-month period ended December 31, 2003, the Company has recorded $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 amounts included in minority interest and preferred dividends of subsidiaries related to these securities for the nine-month period ended September 30, 2003, and the year ended December 31, 2002, were $170.2 million and $147.7 million, respectively. The Company adopted the provisions of FIN 46R related to non-special purpose entities in the first quarter of 2004. The Company considered the provisions of FIN 46R for all subsidiaries and their related power purchase, power sale, or tolling agreements. Factors considered in the analysis include the duration of the agreements, how capacity and energy payments are determined, source and payment terms for fuel, as well as responsibility and payment for operating and maintenance expenses. As a result of these considerations, the Company has determined its power purchase, power sale and tolling agreements do not represent significant variable interests. Accordingly, the Company concluded that it is appropriate to continue to consolidate the power plant projects with ownership interests greater than 50% and not to consolidate the power plants from which it purchases power.

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, 2004 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, contingent liabilities, accrued pension and post-retirement expense 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, which will be amortized over various future periods. To the extent that collection of such costs or payment of such obligations is no longer probable as a result of changes in regulation, the associated regulatory asset or liability is charged or credited to income.

A possible consequence of deregulation of the regulated energy industry is that SFAS 71 may no longer apply. If portions of the Company’s regulated energy operations no longer meet the criteria of SFAS 71, the Company could be required to write off the related regulatory assets and liabilities from its balance sheet, and thus a material adjustment to earnings in that period could result if regulatory assets or liabilities are not recovered in transition provisions of any deregulation legislation.

The Company continues to evaluate the applicability of SFAS 71 to its regulated energy operations and the recoverability of these assets and liabilities through rates as there are on-going changes in the regulatory and economic environment.

Impairment of Long-Lived Assets and Goodwill

The Company’s long-lived assets consist primarily of properties, plants and equipment. Depreciation is 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 87 years, are reasonable.

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 would be 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 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, 2004, primarily using a discounted cash flow methodology. No impairment was indicated as a result of these assessments.

Contingent Liabilities

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. Revisions to contingent liabilities 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 contingent liabilities and subsequent revisions are reflected in income when accruals are recorded or as regulatory treatment dictates. Accruals for contingent liabilities 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 contingent liabilities would be required.

Accrued Pension and Postretirement Expense

Pension and postretirement costs are accrued throughout the year based on results of an annual study performed by external actuaries. In addition to the benefits granted to employees, the timing of the cost of these plans is impacted by assumptions used by the actuaries, including assumptions provided by MEHC for the discount rate and long-term rate of return on assets. Both of these factors require estimates and projections by management and can fluctuate from period to period. Actual returns on assets are significantly affected by stock and bond markets, over which management has little control. The interest rate at which projected benefits are discounted significantly affects amounts expensed. 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 disclosures regarding the Company’s pension and post retirement commitments.

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 $1.5 billion at December 31, 2004. 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 calculation of current and deferred income taxes requires management to apply judgment relating to the application of complex tax laws or related interpretations and uncertainties related to the outcome of tax audits. Changes in such factors may result in changes to management’s estimates, which could require the Company to adjust its currently recorded tax assets and liabilities and record additional income tax expense or benefits.

Revenue Recognition

Revenue is recorded based upon services rendered and electricity, gas and steam delivered, distributed or supplied to the end of the period. The Company records unbilled revenue representing the estimated amounts customers will be billed for services rendered between the meter reading dates in a particular month and the end of that month.

Where billings result in an overrecovery of United Kingdom distribution business revenue against the maximum regulated amount, revenue is deferred in an amount equivalent to the over recovered amount. The deferred amount is deducted from revenue and included in other liabilities. Where there is an under recovery, no anticipation of any potential future recovery is made.

Revenue from the transportation and storage of gas is recognized based on contractual terms and the related volumes. Kern River and Northern Natural Gas are subject to the FERC’s 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 record revenue which is subject to refund based on their best estimate of the final outcome of these proceedings and other third party regulatory proceedings, advice of counsel and estimated total exposure, as well as collection and other risks. The estimate of the refund is recorded in other current liabilities in the accompanying consolidated balance sheets.

Revenue from water and energy delivery is recorded on the basis of the contractual minimum guaranteed water delivery threshold for the respective contract year. If and when cumulative deliveries within a contract year exceed the minimum threshold, additional revenue is recognized. Revenue from long-term electricity contracts is recorded at the lower of the amount billed or the average of the contract, subject to contractual provisions at each project.

Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when title has transferred from seller to buyer. Title fee revenue from real estate transactions and related amounts due to the title insurer are recognized at the closing, which is when consideration is received. Fees related to loan originations are recognized at the closing, which is when services have been provided and consideration is received. To the extent the estimated amount differs from the actual amount, revenue will be affected.

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

The Company is exposed to market risk, including changes in the market price of certain commodities and interest rates. To manage the price volatility relating to these exposures, the Company enters into various financial derivative instruments. Senior management provides the overall direction, structure, conduct and control of the Company’s risk management activities, including the use of financial derivative instruments, authorization and communication of risk management policies and procedures, strategic hedging program guidelines, appropriate market and credit risk limits, and appropriate systems for recording, monitoring and reporting the results of transactional and risk management activities.

Interest Rate Risk

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 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 $396.0 million if interest rates were to increase by 10% from their levels at December 31, 2004. 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, 2003, the Company had fixed-rate long-term debt of $11,369.4 million in aggregate principal amount and having a fair value of $12,015.1 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, 2004, the Company had floating-rate obligations of $493.4 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. If the floating rates were to increase by 1%, the Company’s consolidated interest expense for unhedged floating-rate obligations would increase by approximately $0.4 million each month in which such increase continued based upon December 31, 2004 principal balances.

At December 31, 2003, the Company had floating-rate obligations of $459.8 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.

Currency Exchange Rate Risk

CE Electric UK entered into currency rate swap agreements for its Senior Notes 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 outstanding at December 31, 2004. The agreements extend until maturity on December 30, 2007 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated fair value of these swap agreements at December 31, 2004 and 2003 was $35.7 million and $16.0 million, respectively, based on quotes from the counterparty to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated.

A subsidiary of CE Electric UK entered into 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 $281.1 million of 6.496% Yankee Bonds outstanding at December 31, 2004. The agreements extend until maturity on February 25, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these swap agreements at December 31, 2004 and 2003 was $96.1 million and $62.6 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, 2004 would increase the amount owed by the Company if these swap agreements were terminated by approximately $69.9 million.

Derivatives

As of December 31, 2004, MidAmerican Energy held derivative instruments used for non-trading and trading purposes with the following fair values (in thousands):

Contract Type	Maturity in 2005			Maturity in 2006-08			Total
Non-trading:
Regulated electric assets	$	2,260		$	431		$	2,691
Regulated electric (liabilities)		(10,057	)		(4,817	)		(14,874	)
Regulated gas assets		2,973			1,798			4,771
Regulated gas (liabilities)		(21,921	)		-			(21,921	)
Regulated weather (liabilities)		(4,495	)		-			(4,495	)
Nonregulated electric assets		1,957			372			2,329
Nonregulated electric (liabilities)		(1,158	)		(214	)		(1,372	)
Nonregulated gas assets		5,937			1,919			7,856
Nonregulated gas (liabilities)		(6,606	)		(1,558	)		(8,164	)
Total		(31,110	)		(2,069	)		(33,179	)

Trading:
Nonregulated gas assets		993			-			993
Nonregulated gas (liabilities)		(430	)		(100	)		(530	)
Total		563			(100	)		463

Total MidAmerican Energy assets	$	14,120		$	4,520		$	18,640
Total MidAmerican Energy (liabilities)	$	(44,667	)	$	(6,689	)	$	(51,356	)

Item 8. Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm	58

Consolidated Balance Sheets as of December 31, 2004 and 2003	59

Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002	60

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 2003 and 2002	61

Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002	62

Notes to Consolidated Financial Statements	63

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, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the consolidated 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. An audit includes 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Notes 2 and 10 to the consolidated financial statements, the Company changed its accounting policy for asset retirement obligations and for variable interest entities in 2003.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

February 25, 2005

MIDAMERICAN ENERGY HOLDINGS COMPANY

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands)

	As of December 31,
	2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	960,903		$	660,213
Restricted cash and short-term investments		129,316			55,281
Accounts receivable, net of allowance for doubtful accounts of $26,033 and $26,004		695,761			666,063
Inventories		125,079			123,301
Other current assets		278,219			348,618
Total current assets		2,189,278			1,853,476
Properties, plants and equipment, net		11,607,264			11,180,979
Goodwill		4,306,751			4,305,643
Regulatory assets		451,830			512,549
Other investments		236,258			228,896
Equity investments		210,430			234,370
Deferred charges and other assets		901,751			829,039
Total assets	$	19,903,562		$	19,144,952
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	410,319		$	345,237
Accrued interest		197,813			189,635
Accrued property and other taxes		166,639			112,823
Other liabilities		532,160			420,294
Short-term debt		9,090			48,036
Current portion of long-term debt		1,145,598			500,941
Current portion of parent company subordinated debt		188,543			100,000
Total current liabilities		2,650,162			1,716,966
Other long-term accrued liabilities		2,171,616			1,961,695
Parent company senior debt		2,771,957			2,777,878
Parent company subordinated debt		1,585,810			1,772,146
Subsidiary and project debt		6,304,923			6,674,640
Deferred income taxes		1,281,833			1,299,082
Total liabilities		16,766,301			16,202,407

Deferred income		62,443			69,201
Minority interest		14,119			9,754
Preferred securities of subsidiaries		89,540			92,145

Commitments and contingencies (Note 21)

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; 9,081 and 9,281 shares issued and outstanding at December 31, 2004 and 2003, respectively		-			-
Additional paid-in capital		1,950,663			1,957,277
Retained earnings		1,156,843			999,627
Accumulated other comprehensive loss, net		(136,347	)		(185,459	)
Total stockholders’ equity		2,971,159			2,771,445
Total liabilities and stockholders’ equity	$	19,903,562		$	19,144,952

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

MIDAMERICAN ENERGY HOLDINGS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands)

	Year Ended December 31,
	2004			2003			2002

Operating revenue	$	6,553,388		$	5,965,630		$	4,795,179

Costs and expenses:
Cost of sales		2,751,856			2,400,536			1,843,955
Operating expense		1,637,922			1,512,345			1,302,780
Depreciation and amortization		638,209			602,934			530,078
Gain on CE Gas asset sale (Note 5)		-			-			(54,345	)
Total costs and expenses		5,027,987			4,515,815			3,622,468

Operating income		1,525,401			1,449,815			1,172,711

Other income (expense):
Interest expense		(903,217	)		(760,956	)		(632,133	)
Capitalized interest		20,040			30,494			23,361
Interest and dividend income		38,889			47,908			56,037
Other income		128,205			96,643			40,223
Other expense		(10,125	)		(5,913	)		(28,561	)
Total other income (expense)		(726,208	)		(591,824	)		(541,073	)
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		799,193			857,991			631,638
Income tax expense		264,986			270,276			111,278
Minority interest and preferred dividends of subsidiaries		13,301			183,203			163,468
Income from continuing operations before equity income		520,906			404,512			356,892
Equity income		16,861			38,224			40,520
Income from continuing operations		537,767			442,736			397,412
Loss from discontinued operations, net of tax benefits (Note 3)		(367,561	)		(27,118	)		(17,369	)
Net income available to common and preferred stockholders	$	170,206		$	415,618		$	380,043

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

MIDAMERICAN ENERGY HOLDINGS COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE THREE YEARS ENDED DECEMBER 31, 2004

(Amounts in thousands)

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

Balance, January 1, 2002		9,281		$	-	$	1,553,073		$	223,926		$	(68,832	)	$	1,708,167
Net income		-			-		-			380,043			-			380,043
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			166,880			166,880
Fair value adjustment on cash flow hedges, net of tax of $(10,106)		-			-		-			-			(27,623	)		(27,623	)
Minimum pension liability adjustment, net of tax of $(135,707)		-			-		-			-			(313,456	)		(313,456	)
Unrealized losses on securities, net of tax of $(1,813)		-			-		-			-			(3,204	)		(3,204	)
Total comprehensive income																202,640
Issuance of zero-coupon convertible preferred stock		-			-		402,000			-			-			402,000
Retirement of stock options		-			-		815			(19,960	)		-			(19,145	)
Other equity transactions		-			-		621			-			-			621
Balance, December 31, 2002		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

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

MIDAMERICAN ENERGY HOLDINGS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Year Ended December 31,
		2004			2003			2002
Cash flows from operating activities:
Income from continuing operations	$	537,767		$	442,736		$	397,412
Adjustments to reconcile income from continuing operations to cash flows from continuing operations:
Distributions less income on equity investments		20,022			40,160			(11,383	)
Gain on other items		(71,757	)		(29,264	)		(47,086	)
Depreciation and amortization		638,209			602,934			530,078
Amortization of regulatory assets and liabilities		(1,586	)		(14,363	)		8,709
Amortization of deferred financing costs		20,875			27,748			28,433
Provision for deferred income taxes		176,591			220,136			(18,020	)
Other		16,981			8,211			8,356
Changes in other items:
Accounts receivable and other current assets		(43,600	)		(25,900	)		(200,760	)
Accounts payable and other accrued liabilities		171,457			(17,835	)		78,813
Deferred income		(6,465	)		(9,344	)		(4,839	)
Net cash flows from continuing operations		1,458,494			1,245,219			769,713
Net cash flows from discontinued operations		(33,846	)		(27,296	)		(11,987	)
Net cash flows from operating activities		1,424,648			1,217,923			757,726
Cash flows from investing activities:
Capital expenditures relating to operating projects		(778,300	)		(616,804	)		(528,950	)
Construction and other development costs		(401,090	)		(602,564	)		(813,348	)
Proceeds from notes receivable		169,210			-			-
Acquisitions, net of cash acquired		(36,706	)		(54,263	)		(1,416,937	)
Proceeds from (purchase of) affiliate notes, net		14,118			(32,406	)		-
Sale (purchase) of convertible preferred securities		-			288,750			(275,000	)
Other		2,148			25,786			189,984
Net cash flows from continuing operations		(1,030,620	)		(991,501	)		(2,844,251	)
Net cash flows from discontinued operations		966			(11,666	)		(63,560	)
Net cash flows from investing activities		(1,029,654	)		(1,003,167	)		(2,907,811	)
Cash flows from financing activities:
Proceeds from subsidiary and project debt		375,351			1,157,649			1,485,349
Proceeds from parent company senior debt		249,765			449,295			700,000
Repayments of subsidiary and project debt		(368,417	)		(1,490,986	)		(393,264	)
Repayments of parent company senior and subordinated debt		(100,000	)		(412,551	)		-
Net repayment of subsidiary short-term debt		(43,949	)		(31,750	)		(472,835	)
Purchase and retirement of common stock		(20,000	)		-			-
Proceeds from issuance of trust preferred securities		-			-			1,273,000
Proceeds from issuance of preferred stock		-			-			402,000
Net repayment of parent company revolving credit facility		-			-			(153,500	)
Repayment of other obligations		-			-			(94,297	)
Increase in restricted cash and investments		(48,515	)		(4,024	)		(41,524	)
Redemption of preferred securities of subsidiaries		(2,606	)		(1,176	)		(127,908	)
Other		(27,167	)		(91,387	)		(40,962	)
Net cash flows from continuing operations		14,462			(424,930	)		2,536,059
Net cash flows from discontinued operations		(137,297	)		(1,407	)		19,175
Net cash flows from financing activities		(122,835	)		(426,337	)		2,555,234
Effect of exchange rate changes		28,531			27,364			52,536
Net change in cash and cash equivalents		300,690			(184,217	)		457,685
Cash and cash equivalents at beginning of period		660,213			844,430			386,745
Cash and cash equivalents at end of period	$	960,903		$	660,213		$	844,430

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

MIDAMERICAN ENERGY HOLDINGS COMPANY

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 on seven distinct platforms: MidAmerican Energy Company (“MidAmerican Energy”), Kern River Gas Transmission Company (“Kern River”), Northern Natural Gas Company (“Northern Natural Gas”), CE Electric UK Funding (“CE Electric UK”) (which 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 and related operations) 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 the United Kingdom, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.

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 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 the United Kingdom 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. Under Financial Accounting Standards Board (“FASB”) Interpretation No. 46R, “Consolidation of Variable Interest Entities” (“FIN 46R”) these trusts, by design, are considered variable interest entities, with no variable interest holder being considered the primary beneficiary, thus requiring the reporting entity to deconsolidate the trust. 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 2003 and 2002 consolidated financial statements and supporting note disclosures have been reclassified to conform to the fiscal 2004 presentation, including the reclassification of activity as discontinued operations (see Note 3). Such reclassification did not impact previously reported net income or retained earnings.

Use of Estimates

The preparation of 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 disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those 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, which will be amortized over various future periods. To the extent that collection of such costs or payment of such obligations is no longer probable as a result of changes in regulation, the associated regulatory asset or liability is charged or credited to income.

A possible consequence of deregulation of the regulated energy industry is that SFAS 71 may no longer apply. If portions of the Company’s regulated energy operations no longer meet the criteria of SFAS 71, the Company could be required to write off the related regulatory assets and liabilities from its consolidated balance sheet, and thus a material adjustment to earnings in that period could result if regulatory assets or liabilities are not recovered in transition provisions of any deregulation legislation.

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,
	2004			2003		2002

Interest paid, net of interest capitalized	$	867,181		$	706,039	$	588,972
Income taxes (refunded) paid	$	(16,616	)	$	9,911	$	101,225
Non-cash transaction - ROP note received under NIA Arbitration Settlement	$	-		$	97,000	$	-

Cash paid for interest for the years ended December 31, 2003 and 2002 does not include $170,151 and $147,667, respectively, of interest paid on subordinated debt, which is included in minority interest and preferred dividends of subsidiaries in the consolidated statements of operations. These amounts were not reclassified pursuant to the FIN 46R.

Restricted Cash and Investments

The restricted cash and short-term investments balance recorded separately in restricted cash and short-term investments and in deferred charges and other assets, was $164.5 million and $119.5 million at December 31, 2004 and 2003, respectively, and includes commercial paper and money market securities. The balance is mainly composed of amounts deposited in restricted accounts from which the Company will source its debt service reserve requirements relating to the projects, customer deposits held in escrow, custody deposits, and unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project.

The Company’s nuclear decommissioning trust funds and other marketable securities are classified as available for sale and are accounted for at fair value.

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.

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.

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:

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.

Properties, Plants and Equipment, Net

Properties, plants and equipment are recorded at historical cost. 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 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 87 years, are reasonable.

Capitalized costs for gas reserves, other than costs of unevaluated exploration projects and projects awaiting development consent, are depleted using the units of production method. Depletion is calculated based on hydrocarbon reserves of properties in the evaluated pool estimated to be commercially recoverable and include anticipated future development costs in respect of those reserves.

Impairment of Long-Lived Assets

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, 2004 primarily using a discounted cash flow methodology. No impairment was indicated as a result of these assessments.

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 subsidiaries that apply SFAS 71. Interest and AFUDC for subsidiaries that apply SFAS 71 are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives.

Deferred Financing Cost

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

Contingent Liabilities

Income Taxes

Revenue Recognition

Revenue from the transportation and storage of gas are recognized based on contractual terms and the related volumes. 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 record revenue which is subject to refund based on their best estimate of the final outcome of these proceedings and other third party regulatory proceedings, advice of counsel and estimated total exposure, as well as collection and other risks. The estimate of the refund is recorded in other current liabilities in the accompanying consolidated balance sheets.

Financial Instruments

The Company currently utilizes swap agreements and forward purchase agreements to manage market risks and reduce its exposure resulting from fluctuation in interest rates, foreign currency exchange rates and electric and gas prices. For interest rate swap agreements, the net cash amounts paid or received on the agreements are accrued and recognized as an adjustment to interest expense. Gains and losses related to gas forward contracts are deferred and included in the measurement of the related gas purchases. These instruments are either exchange traded or with counterparties of high credit quality; therefore, the risk of nonperformance by the counterparties is considered to be negligible.

New Accounting Pronouncements

In December 2003, the FASB issued FIN 46R, which served to clarify guidance in FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51.” 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 the amounts previously classified as mandatorily redeemable preferred securities of subsidiary trusts, in the amount of $1.9 billion, being reclassified to parent company subordinated debt in the accompanying consolidated balance sheets. In addition, amounts previously recorded as minority interest and preferred dividends of subsidiaries are now recorded as interest expense in the accompanying consolidated statements of operations, prospectively. For the year ended December 31, 2004, and the three-month period ended December 31, 2003, the Company has recorded $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 amounts included in minority interest and preferred dividends of subsidiaries related to these securities for the nine-month period ended September 30, 2003, and the year ended December 31, 2002, were $170.2 million and $147.7 million, respectively. The Company adopted the provisions of FIN 46R related to non-special purpose entities in the first quarter of 2004. The Company considered the provisions of FIN 46R for all subsidiaries and their related power purchase, power sale, or tolling agreements. Factors considered in the analysis include the duration of the agreements, how capacity and energy payments are determined, source and payment terms for fuel, as well as responsibility and payment for operating and maintenance expenses. As a result of these considerations, the Company has determined its power purchase, power sale and tolling agreements do not represent significant variable interests. Accordingly, the Company concluded that it is appropriate to continue to consolidate the power plant projects with ownership interests greater than 50% and not to consolidate the power plants from which it purchases power.

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. 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”).

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 has been 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.
	2004			2003			2002

Total revenue	$	3,401		$	659		$	288

Losses from discontinued operations	$	(42,695	)	$	(46,423	)	$	(29,059	)
Costs of disposal activities, net		(4,134	)		-			-
Asset impairment charges, including goodwill		(532,009	)		-			-
Income tax benefits		211,277			19,305			11,690
Loss from discontinued operations, net of tax	$	(367,561	)	$	(27,118	)	$	(17,369	)

4. Acquisitions

HomeServices

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. Additionally in 2004, HomeServices paid an earnout of $6.0 million based on 2004 financial performance measures. These purchases were financed using HomeServices’ cash balances and revolving credit facility.

In 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of $106.1 million, net of cash acquired, plus working capital and certain other adjustments. Additionally in 2003, HomeServices paid an earnout of $17.6 million based on 2002 financial performance measures. These purchases were financed using HomeServices’ cash balances, revolving credit facility and $40.0 million from MEHC, which was contributed to HomeServices as equity.

Kern River

On March 27, 2002, the Company acquired Kern River from The Williams Companies, Inc. (“Williams”). At the date of acquisition, Kern River owned a 926-mile interstate pipeline transporting Rocky Mountain and Canadian natural gas to markets in California, Nevada and Utah.

The Company paid $419.7 million, net of cash acquired and a working capital adjustment, for Kern River’s gas pipeline business. The acquisition has been accounted for as a purchase business combination. The Company completed the allocation of the purchase price to the assets and liabilities acquired during 2003. The results of operations for Kern River are included in the Company’s results beginning March 27, 2002.

The recognition of goodwill resulted from various attributes of Kern River’s operations and business in general. These attributes include, but are not limited to:

· Opportunities for expansion;

· Generally high credit quality shippers contracting with Kern River;

· Kern River’s strong competitive position;

· Exceptional operating track record and state-of-the-art technology;

· Strong demand for gas in the Western markets; and

· An ample supply of low-cost gas.

There is no assurance that these attributes will continue to exist to the same degree as believed at the time of the acquisition.

In connection with the acquisition of Kern River, MEHC issued $323.0 million of 11% Company-obligated mandatorily redeemable preferred securities of a subsidiary trust due March 12, 2012 with scheduled principal payments beginning in 2005 and $127.0 million of no par, zero coupon convertible preferred stock to Berkshire Hathaway. Each share of preferred stock is convertible at the option of the holder into one share of the Company’s common stock subject to certain adjustments as described in the MEHC Amended and Restated Articles of Incorporation.

Northern Natural Gas

On August 16, 2002, the Company acquired Northern Natural Gas from Dynegy Inc. Northern Natural Gas is a 16,500-mile interstate pipeline extending from southwest Texas to the upper Midwest region of the United States.

The Company paid $882.7 million for Northern Natural Gas, net of cash acquired and a working capital adjustment. The acquisition has been accounted for as a purchase business combination. The Company completed the allocation of the purchase price to the assets and liabilities acquired during 2003. The results of operations for Northern Natural Gas are included in the Company’s results beginning August 16, 2002.

The recognition of goodwill resulted from various attributes of Northern Natural Gas’ operations and business in general. These attributes include, but are not limited to:

· Generally high credit quality shippers contracting with Northern Natural Gas;

· Northern Natural Gas’ strong competitive position;

· Strategic location in the high demand Upper Midwest markets;

· Flexible access to an ample supply of low-cost gas;

· Exceptional operating track record; and

· Opportunities for expansion.

There is no assurance that these attributes will continue to exist to the same degree as believed at the time of the acquisition.

In connection with the acquisition of Northern Natural Gas, MEHC issued $950.0 million of 11% Company-obligated mandatorily redeemable preferred securities of a subsidiary trust due August 31, 2011, with scheduled principal payments beginning in 2003, to Berkshire Hathaway.

The following pro forma financial information of the Company represents the unaudited pro forma results of operations as if the Kern River and Northern Natural Gas acquisitions, and the related financings, had occurred at the beginning of 2002. These pro forma results have been prepared for comparative purposes only and do not profess to be indicative of the results of operations which would have been achieved had these transactions been completed at the beginning of the year, nor are the results indicative of the Company’s future results of operations (in millions):

	Year Ended
	December 31,
		2002

Revenue	$	5,299.4
Income before cumulative effect of change in accounting principle		285.5
Net income available to common and preferred shareholders		285.5

5. Dispositions and Other Items

CE Gas Asset Sale

In May 2002, CalEnergy Gas (Holdings) Limited (“CE Gas”), an indirect wholly owned subsidiary of the Company, executed the sale of several of its U.K. natural gas assets to Gaz de France for approximately $200.0 million (£137.0 million), which was included in other investing activities in the accompany consolidated statement of cash flows in 2002. CE Gas sold its interest in four natural gas-producing fields located in the southern basin of the U.K. North Sea (Anglia, Johnston, Schooner and Windermere). The transaction also included the sale of rights in four gas fields (in development/construction) and three exploration blocks owned by CE Gas. The Company recorded pre-tax and after-tax income of $54.3 million and $41.3 million, respectively, which includes a write off of non-deductible goodwill of $49.6 million.

Teesside Power Limited (“TPL”)

The Company has a 15.4% interest in TPL, which owns and operates a 1,875 MW combined cycle gas-fired power plant. Enron Corp. (“Enron”), which through its subsidiaries has a 42.5% interest, previously operated TPL. TPL is now in administration and administrators have been appointed to run its business and are attempting to find a buyer. The Company wrote-off its investment in TPL during 2001. Shareholders in TPL had previously utilized TPL’s taxable losses with an obligation to reimburse TPL later in the project’s life. In May 2002, TPL executed a restructuring and stabilization agreement with its lenders. The contract included an agreement between TPL and its shareholders with respect to the waiver of these repayment obligations. In May 2002, TPL released $35.7 million due to the repayment obligation being waived which is reflected as a tax benefit in income tax expense in 2002.

6. Properties, Plants and Equipment, Net

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

	Depreciation
	Life		2004			2003

Utility generation and distribution system		10-50 years	$	10,149,818		$	8,987,158
Interstate pipelines’ assets		3-87 years		3,566,578			3,470,117
Independent power plants		10-30 years		1,384,660			1,395,782
Mineral and gas reserves and exploration assets		5-30 years		101,472			554,780
Utility non-operational assets		3-30 years		465,297			429,228
Other assets		3-10 years		167,150			146,286
Total operating assets				15,834,975			14,983,351
Accumulated depreciation and amortization				(4,800,372	)		(4,260,643	)
Net operating assets				11,034,603			10,722,708
Construction in progress				572,661			458,271
Properties, plants and equipment, net			$	11,607,264		$	11,180,979

7. Investment in CE Generation

The Company holds a 50% interest in CE Generation, LLC (“CE Generation”) and accounts for this interest as an equity investment. The equity investment in CE Generation at December 31, 2004 and 2003 was $188.7 million and $209.4 million, respectively. The following is summarized financial information for CE Generation as of and for the years ended December 31 (in thousands):

		2004			2003		2002
Revenue	$	444,228		$	487,422	$	510,082
Income (loss) before cumulative effect of change in
accounting principle		(3,084	)		37,341		58,314
Net income (loss)		(3,084	)		34,874		58,314
Current assets		124,734			260,551
Total assets		1,447,388			1,708,742
Current liabilities		115,153			253,237
Long-term debt, including current portion		722,650			924,565

As part of its annual impairment test, CE Generation determined on December 9, 2004 that a portion of the carrying value of the Power Resources project’s long-lived assets were 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 No. 144, “Accounting for the Impairment of Long-Lived Assets,” 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 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.

8. Other Income and Expense

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

	2004		2003		2002

Gain on Enron note receivable	$	72,210	$	-	$	-
Gain on CE Casecnan settlement		-		31,889		-
Allowance for equity funds used during construction		20,476		26,708		19,366
Gain on Mirant bankruptcy claim		14,750		-		-
Gain on Williams preferred stock		-		13,750		2,750
Corporate-owned life insurance income		5,447		6,317		1,330
Gain on sale of other assets and investments		3,609		4,183		7,519
Other		11,713		13,796		9,258
Total other income	$	128,205	$	96,643	$	40,223

Other expense for the years ending December 31, 2004, 2003 and 2002 was $10.1 million, $5.9 million and $28.6 million, respectively. In 2002, MidAmerican Energy recorded an impairment of its investment in airplane leases and other non-regulated investments of $21.7 million.

Sale of Enron Note Receivable and Receipt of Cash

CE Casecnan Water and Energy Company (“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”) National Irrigation Administration (“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 ROP $97.0 million 8.375% 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. The ROP Note is included in other current assets in the accompanying consolidated balance sheet at December 31, 2003.

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.

Mirant Americas Energy Marketing (“Mirant”) Claim

In July 2003, Mirant filed Chapter 11 bankruptcy. On January 13, 2004, Kern River filed a proof of claim with the bankruptcy court for an aggregate total of $210.2 million, which Kern River believed was secured by the $14.8 million in proceeds received from its letter of credit and held as a cash security deposit. In May 2004, the bankruptcy court issued an order permitting Kern River to apply 100% of the $14.8 million it held in cash collateral to its claim for damages. On October 12, 2004, Mirant raised an objection to Kern River’s claim asserting, among other things, that Kern River had not included a discount adjustment or mitigation to the claim. On November 11, 2004, Kern River filed an amended proof of claim of $138.8 million, reflecting discounting, mitigation and other adjustments. The amended proof of claim excludes the $14.8 million already received by Kern River. Kern River can not determine at this time if it will collect any portion of the balance of the claim or be able to remarket the rejected capacity.

Williams Preferred Stock

On March 27, 2002, the Company invested $275.0 million in Williams in exchange for shares of 9⁷/8% cumulative convertible preferred stock of Williams. Dividends on 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 9⁷/8% 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.

9. Regulatory Assets and Liabilities

The principal components of the Company’s regulatory assets and liabilities were as follows as of December 31 (in thousands):

	As of December 31,
	Weighted Average
		Remaining Life		2004		2003

Regulatory assets:
Deferred income taxes, net		24 years	$	160,662	$	138,192
Computer systems development costs		7 years		63,637		72,787
System levelized account		25 years		53,576		54,109
Minimum pension liability adjustment		N/A		41,136		36,795
Unrealized loss on regulated hedges		1 year		36,794		14,248
Pipe recoating and reconditioning costs		87 years		22,406		22,315
Asset retirement obligations		9 years		20,875		90,556
Debt refinancing costs		7 years		15,365		19,698
Environmental costs		3 years		9,284		13,995
Nuclear generation assets		28 years		6,727		7,522
Cooper Nuclear Station capital improvement costs		-		-		7,314
Other		Various		21,368		35,018
Total			$	451,830	$	512,549

Regulatory liabilities:
Cost of removal accrual		24 years	$	428,719	$	408,608
Iowa electric settlement accrual		3 years		181,188		144,418
Asset retirement obligations		49 years		53,259		-
Unrealized gain on regulated hedges		2 years		7,462		15,122
Environmental insurance recovery		3 years		3,599		3,781
Nuclear insurance reserve		49 years		3,262		2,561
Other		Various		5,278		10,250
Total			$	682,767	$	584,740

Of the regulatory assets listed above, only the nuclear generation assets at MidAmerican Energy and the computer systems development costs, the system levelized account, and the pipe recoating and reconditioning costs at Northern Natural Gas are included in rate base and earn a return.

The decrease in the asset retirement obligation regulatory asset and the establishment of a related regulatory liability is the result of a 20-year extension to the operating license of Quad Cities Generating Station and its impact on the timing of related cash flows. Regulatory liabilities are included in other long-term accrued liabilities in the accompanying consolidated balance sheets.

10. Asset Retirement Obligations

On January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” and recognized a liability for legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. Concurrent with the recognition of the liability, the estimated cost of the asset retirement obligation (“ARO”) was capitalized and is being depreciated over the remaining life of the asset. The difference between the ARO liability, the ARO net asset and amounts recovered from regulated customers to satisfy such liabilities is recorded as a regulatory asset or liability.

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):

	2004			2003

Balance, January 1	$	284,007		$	289,323
Revision to nuclear decommissioning ARO liability		(120,098	)		(21,902	)
Addition for new wind power facilities		2,777			-
Accretion		15,877			16,586
Balance, December 31	$	182,563		$	284,007

At December 31, 2004, $154.2 million of the ARO liability pertained to the decommissioning of Quad Cities Station. Also, at December 31, 2004, $207.5 million of assets reflected in other investments in the accompanying consolidated balance sheet are restricted for satisfying the Quad Cities Station ARO liability.

The 2004 revision is 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 Nuclear Regulatory Commission (“NRC”) in October 2004 and its impact on the timing of related cash flows. The 2003 revision to the nuclear decommissioning ARO liability was due to the results of a decommissioning study performed by the plant operator.

In addition to the ARO liabilities, MidAmerican Energy has accrued for the cost of removing other electric and gas assets through its depreciation rates, in accordance with accepted regulatory practices. These accruals are reflected in other long-term accrued liabilities in the accompanying consolidated balance sheets and total $428.7 million and $408.6 million at December 31, 2004 and 2003, respectively.

11. Short-Term Debt

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

		2004		2003
MidAmerican Energy commercial paper	$	-	$	48,000
HomeServices revolving credit facilities		9,052		-
Other		38		36
Total short-term debt	$	9,090	$	48,036

Parent Company Revolving Credit Facilities

In the second quarter of 2003, the Company terminated its $400.0 million credit facility. On June 6, 2003, the Company closed on a new $100.0 million revolving credit facility which expires on June 6, 2006. The facility supports letters of credit of which $70.0 million were outstanding at December 31, 2004. No borrowings were outstanding at December 31, 2004 or 2003. The facility, which was not drawn on during 2004, carries a variable interest rate based on LIBOR and ranged from 2.02% to 2.255% in 2003.

MidAmerican Energy Short-Term Debt

As of December 31, 2004, MidAmerican Energy has in place a $425.0 million revolving credit facility, which expires on November 18, 2009, and supports its $304.6 million commercial paper program and its variable rate pollution control revenue obligations, all of which was available at December 31, 2004. In addition, MidAmerican Energy has a $5.0 million line of credit which expires on July 1, 2005. There was no commercial paper outstanding at December 31, 2004, and commercial paper totaled $48.0 million at December 31, 2003. MHC Inc., an indirect wholly-owned subsidiary of the Company, has a $4.0 million line of credit, expiring July 1, 2005, under which no borrowings were outstanding at December 31, 2004 or 2003. The commercial paper, bank notes and outstanding line of credit had a weighted average interest rate of 0.98% at December 31, 2003.

HomeServices Revolving Credit Facilities

HomeServices maintains a $125.0 million senior secured revolving credit facility, which expires in November 2005. Amounts outstanding under this revolving credit facility are secured by a pledge of the capital stock of all of the existing and future subsidiaries of HomeServices and bear interest, at HomeServices’ option, at either the prime lending rate or LIBOR plus a fixed spread of 1.25% to 2.25%, which varies based on HomeServices’ cash flow leverage ratio. The spread was 1.25% at December 31, 2004 and 2003. No borrowings were outstanding at December 31, 2004 or 2003. In addition, HomeServices has in place two mortgage warehouse lines of credit totaling $20.0 million, which expire on March 31, 2005 and October 31, 2005, and bear interest at LIBOR plus 1.75% and LIBOR plus 2.25%, respectively. The balances outstanding on these mortgage warehouse lines of credit at December 31, 2004, totaled $9.1 million. There were no borrowings outstanding at December 31, 2003. The mortgage warehouse lines of credit had weighted average interest rates of 4.54% and 4.21%, respectively, at December 31, 2004.

12. Parent Company Senior Debt

Parent company senior debt is unsecured senior obligations of MEHC and consists of the following at December 31 (in thousands):

		2004			2003
7.23% Senior Notes, due 2005	$	260,000		$	260,000
4.625% Senior Notes, due 2007		199,403			199,225
7.63% Senior Notes, due 2007		350,000			350,000
3.50% Senior Notes, due 2008		449,497			449,373
7.52% Senior Notes, due 2008		450,000			450,000
7.52% Senior Notes, due 2008 (Series B)		101,037			101,267
5.875% Senior Notes, due 2012		499,906			499,898
5.00% Senior Notes, due 2014		249,797			-
8.48% Senior Notes, due 2028		475,000			475,000
Fair value adjustments and other		(2,683	)		(6,885	)
Total Parent Company Senior Debt		3,031,957			2,777,878
Less current portion		(260,000	)		-
Total Long-Term Parent Company Senior Debt	$	2,771,957		$	2,777,878

On February 12, 2004, MEHC issued $250.0 million, net of discount, of its 5.00% Senior Notes with a final maturity on February 15, 2014. The proceeds were used to satisfy a demand made by its affiliate, Salton Sea Funding Corporation (“Funding Corporation”), for $136.4 million, the amount remaining on MEHC’s guarantee of Funding Corporation’s 7.475% Senior Secured Series F Bonds due November 30, 2018 (“Series F Bonds”), and for other general corporate purposes.

On May 16, 2003, MEHC issued $450.0 million, net of discount, of its 3.50% Senior Notes with a final maturity on May 15, 2008. The proceeds were used for general corporate purposes.

13. 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. 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 at December 31 (in thousands):

		2004			2003
CalEnergy Capital Trust II — 6.25%, due 2012	$	104,645		$	104,645
CalEnergy Capital Trust III — 6.5%, due 2027		269,980			269,980
MidAmerican Capital Trust I — 11%, due 2010		454,772			454,772
MidAmerican Capital Trust II — 11%, due 2011		700,000			800,000
MidAmerican Capital Trust III — 11%, due 2012		323,000			323,000
Fair value adjustment		(78,044	)		(80,251	)
Total Parent Company Subordinated Debt		1,774,353			1,872,146
Less current portion		(188,543	)		(100,000	)
Long-Term Parent Company Subordinated Debt	$	1,585,810		$	1,772,146

MEHC owns all of the common securities of the Trusts. The Trust Securities have a liquidation preference of $50 each (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.

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 11% 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.

14. Subsidiary and Project Debt

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.

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, 2004, 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 (the “Cordova project”) 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 at December 31 (in thousands):

		2004			2003
MidAmerican Funding	$	700,000		$	700,000
MidAmerican Energy		1,422,527			1,128,647
CE Electric UK		2,504,801			2,467,214
Kern River		1,214,808			1,276,174
Northern Natural Gas		799,614			799,472
CE Casecnan		197,098			246,458
Leyte Projects		105,664			172,813
Cordova Funding		206,663			214,761
Funding Corporation		-			136,384
HomeServices		32,963			37,558
Other, including fair value adjustments		6,383			(3,900	)
Total Subsidiary and Project Debt		7,190,521			7,175,581
Less current portion		(885,598	)		(500,941	)
Total Long-Term Subsidiary and Project Debt	$	6,304,923		$	6,674,640

MidAmerican Funding

The components of MidAmerican Funding’s, a wholly owned subsidiary of MEHC, Senior Notes and Bonds consist of the following at December 31 (in thousands):

		2004		2003
6.339% Senior Notes, due 2009	$	175,000	$	175,000
6.75% Senior Notes, due 2011		200,000		200,000
6.927% Senior Bonds, due 2029		325,000		325,000
Total MidAmerican Funding	$	700,000	$	700,000

MidAmerican Funding may use distributions that it receives from its subsidiaries to make payments on the Notes and Bonds. These subsidiaries must make payments on their own indebtedness before making distributions to MidAmerican Funding. These distributions are also subject to utility regulatory restrictions agreed to by MidAmerican Energy in March 1999, whereby it committed to the Iowa Utilities Board (“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.

MidAmerican Energy

The components of MidAmerican Energy’s Mortgage Bonds, Pollution Control Revenue Obligations and Notes consist of the following at December 31 (in thousands):

		2004			2003
Mortgage bonds:
7.7% Series, due 2004	$	-		$	55,630
7% Series, due 2005		90,500			90,500
Pollution control revenue obligations:
6.1% Series, due 2007		1,000			1,000
5.95% Series, due 2023		29,030			29,030
Variable rate series:
Due 2016 and 2017, 2.05% and 1.26%		37,600			37,600
Due 2023 secured by general mortgage bond, 2.05% and 1.26%		28,295			28,295
Due 2023, 2.05% and 1.26%		6,850			6,850
Due 2024, 2.05% and 1.26%		34,900			34,900
Due 2025, 2.05% and 1.26%		12,750			12,750
Notes:
6.375% Series, due 2006		160,000			160,000
5.125% Series, due 2013		275,000			275,000
4.65% Series, due 2014		350,000			-
6.75% Series, due 2031		400,000			400,000
Obligations under capital lease		1,524			2,060
Unamortized debt premium and discount, net		(4,922	)		(4,968	)
Total MidAmerican Energy	$	1,422,527		$	1,128,647

MidAmerican Energy’s 7.7% series of mortgage bonds, totaling $55.6 million, matured on May 17, 2004. On October 1, 2004, MidAmerican Energy issued $350.0 million of 4.65% medium-term notes due October 1, 2014. The proceeds were used for general corporate purposes.

On January 14, 2003, MidAmerican Energy issued $275.0 million of 5.125% medium-term notes due in 2013. The proceeds were used to refinance existing debt and for other corporate purposes.

CE Electric UK

The components of CE Electric UK and its subsidiaries’ long-term debt consist of the following at December 31 (in thousands):

		2004		2003
6.853% Senior Notes, due 2004	$	-	$	117,112
8.625% Bearer bonds, due 2005		192,045		178,877
6.995% Senior Notes, due 2007		237,000		236,174
6.496% Yankee Bonds, due 2008		281,113		281,149
Variable Rate Reset Trust Securities, due 2020 (5.88% and 4.39%)		308,361		287,539
8.875% Bearer bonds, due 2020		191,955		178,644
9.25% Eurobonds, due 2020		485,654		458,187
7.25% Sterling Bonds, due 2022		377,674		351,242
7.25% Eurobonds, due 2028		378,202		352,768
CE Gas Credit Facility, 6.36%		52,797		25,522
Total CE Electric UK	$	2,504,801	$	2,467,214

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 has 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.

Kern River

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

		2004		2003
6.676% Senior Notes, due 2016	$	439,000	$	464,000
4.893% Senior Notes, due 2018		775,808		812,174
Total Kern River	$	1,214,808	$	1,276,174

On August 13, 2001, Kern River issued $510.0 million in debt securities. The offering was in the form of $510.0 million of 15-year amortizing Senior Notes bearing a fixed rate of interest of 6.676%. For the Senior Notes, $405.0 million will be amortized through June 2016, with a final payment of $105.0 million to be made on July 31, 2016.

On May 1, 2003, Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836.0 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the $815.0 million of outstanding borrowings under Kern River’s $875.0 million credit facility. Kern River entered into this credit facility in 2002 to finance the construction of its 717 mile expansion.

Northern Natural Gas

The components of Northern Natural Gas’ Senior Notes consist of the following at December 31 (in thousands):

		2004			2003
6.875% Senior Notes, due 2005	$	100,000		$	100,000
6.75% Senior Notes, due 2008		150,000			150,000
7.00% Senior Notes, due 2011		250,000			250,000
5.375% Senior Notes, due 2012		300,000			300,000
Unamortized debt discount		(386	)		(528	)
Total Northern Natural Gas	$	799,614		$	799,472

CE Casecnan

On November 27, 1995, CE Casecnan issued $371.5 million of notes and bonds to finance the construction of the CE Casecnan project. The CE Casecnan Notes and Bonds consist of the following at December 31 (in thousands):

		2004		2003
11.45% Senior Secured Series A Notes, due in 2005	$	48,750	$	91,250
11.95% Senior Secured Series B Bonds, due in 2010		148,348		155,208
Total CE Casecnan	$	197,098	$	246,458

The CE Casecnan Notes and Bonds are subject to redemption at the Company’s option as provided in the Trust Indenture. The CE Casecnan Notes and Bonds are also subject to mandatory redemption based on certain conditions.

Leyte Projects

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

		2004		2003
Mahanagdong Project 6.92% Term Loan, due 2007	$	51,537	$	72,151
Mahanagdong Project 7.60% Term Loan, due 2007		11,428		16,000
Malitbog Project 4.99% and 3.67%, due 2005		11,866		26,378
Malitbog Project 9.176% Term Loan, due 2006		6,580		14,628
Upper Mahiao Project 5.95% Term Loan, due 2006		24,253		43,656
Total Leyte Projects	$	105,664	$	172,813

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 $44.6 million and $40.3 million at December 31, 2004 and 2003, respectively.

Cordova Funding

On September 10, 1999, Cordova Funding Corporation (“Cordova Funding”), a wholly owned subsidiary of the Company, closed the $225.0 million aggregate principal amount financing for the construction of the Cordova project. The proceeds were loaned to Cordova Energy and consist of the following at December 31 (in thousands):

		2004		2003
8.48% Senior Secured Bonds, due 2019	$	11,716	$	12,175
8.64% Senior Secured Bonds, due 2019		85,893		89,260
8.79% Senior Secured Bonds, due 2019		28,758		29,885
8.82% Senior Secured Bonds, due 2019		53,384		55,476
9.07% Senior Secured Bonds, due 2019		26,912		27,965
Total Cordova Funding	$	206,663	$	214,761

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 of which such maximum amount was $13.0 million as of December 31, 2004.

As of December 31, 2004, 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.

Funding Corporation

CalEnergy Minerals LLC (“Minerals”), a wholly-owned indirect subsidiary of MEHC, was one of several guarantors of the Funding Corporation’s debt. As a result of a note allocation agreement, Minerals was primarily responsible for $136.4 million of the Series F Bonds. In 1999, MEHC guaranteed a specified portion of the scheduled debt service on the Series F Bonds equal to the then current principal amount of $136.4 million and associated interest.

On March 1, 2004, Funding Corporation completed the redemption of an aggregate principal amount of $136.4 million of the Series F Bonds, pro rata, at a redemption price of 100% of such aggregate outstanding principal amount, plus accrued interest to the date of redemption. Funding Corporation also made a demand on MEHC for the full amount remaining on MEHC’s guarantee of the Series F Bonds in order to fund the redemption. MEHC made the requisite payment and, as a result, it has no further liability with respect to its guarantee. The Company had a non-cash, after-tax loss, recorded in loss from discontinued operations in the accompanying consolidated statement of operations, of $6.4 million as a result of the redemption of the Series F Bonds.

HomeServices

In November 1998, HomeServices issued $35.0 million of 7.12% fixed-rate private placement senior notes due in annual increments of $5.0 million beginning in 2004. As of December 31, 2004 and 2003, the balance of the HomeServices Senior Notes was $30.0 million and $35.0 million, respectively.

In addition to the senior notes, HomeServices has outstanding capital leases and other long-term debt, with varying interest rates, totaling $3.0 million and $2.6 million at December 31, 2004 and 2003, respectively.

Annual Repayments of Long-Term Debt

The annual repayments of parent company, subsidiary and project debt for the years beginning January 1, 2005 and thereafter are as follows (in thousands):

	2005	2006	2007	2008	2009	Thereafter	Total
Parent Company senior debt	$260,000	$ -	$ 550,000	$1,000,000	$ -	$1,221,957	$3,031,957
Parent Company subordinated debt	188,543	234,021	234,021	234,021	234,021	649,726	1,774,353
MidAmerican Funding	-	-	-	-	175,000	525,000	700,000
MidAmerican Energy	91,018	160,000	1,000	-	-	1,170,509	1,422,527
CE Electric UK	500,406	9,720	253,925	294,051	4,913	1,441,786	2,504,801
Kern River	62,784	66,128	69,472	72,816	74,906	868,702	1,214,808
Northern Natural Gas	99,963	-	-	150,000	-	549,651	799,614
CE Casecnan	54,753	36,016	37,730	37,730	13,720	17,149	197,098
Leyte Projects	63,034	30,037	12,593	-	-	-	105,664
Cordova Funding	7,875	4,500	4,163	4,725	6,412	178,988	206,663
HomeServices	5,765	5,000	5,000	5,000	5,000	7,198	32,963
Other, including purchase accounting adjustments	-	-	-	-	-	6,383	6,383
Totals	$1,334,141	$545,422	$1,167,904	$1,798,343	$513,972	$6,637,049	$11,996,831

Fair Value

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 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, 2003, the Company had fixed-rate long-term debt of $11,369.4 million in principal amount and having a fair value of $12,015.1 million. In addition, at December 31, 2003, the Company had floating-rate obligations of $459.8 million. The fair value of the floating-rate obligations and the short-term debt approximates their carrying amounts.

15. Income Taxes

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

	Year Ended December 31,
		2004			2003			2002
Current:
Federal	$	18,794		$	(48,911	)	$	57,236
State		(9,862	)		10,901			17,476
Foreign		79,463			88,150			54,586
		88,395			50,140			129,298
Deferred:
Federal		112,719			141,795			(4,900	)
State		607			10,833			(13,640	)
Foreign		63,265			67,508			520
		176,591			220,136			(18,020	)
Total	$	264,986		$	270,276		$	111,278

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

	2004		2003		2002
Federal statutory rate	35.0	%	35.0	%	35.0	%
Investment and energy tax credits	(0.6	)	(0.5	)	(0.7	)
State taxes, net of federal tax effect	2.2		1.8		1.2
Equity income	0.7		1.6		2.3
Dividends on preferred securities of subsidiaries	-		(6.9	)	(8.3	)
Tax effect of foreign income	0.3		0.5		(4.8	)
Non-recurring items on CE Electric UK, net of tax effect of foreign income	-		(0.5	)	(8.3	)
Dividends received deduction	-		(1.1	)	(1.9	)
Effects of ratemaking	(0.9	)	0.9		1.0
Other items, net	(3.5	)	0.7		2.1
Effective tax rate	33.2	%	31.5	%	17.6	%

Deferred tax liabilities (assets) consist of the following at December 31 (in thousands):

		2004			2003
Properties, plants and equipment, net	$	1,700,884		$	1,611,744
Income taxes recoverable through future rates		163,108			142,597
Employee benefits		56,656			43,005
Reacquired debt		3,877			5,665
Fuel cost recoveries		6,028			12,864
		1,930,553			1,815,875

Minimum pension liability adjustment		(172,350	)		(147,279	)
Revenue sharing accruals		(80,220	)		(64,192	)
Accruals not currently deductible for tax purposes		(54,402	)		(55,290	)
Nuclear reserve and decommissioning		(27,112	)		(35,955	)
Deferred income		(34,458	)		(37,819	)
Net operating loss (“NOL”) and credit carryforwards		(267,051	)		(161,659	)
Other		(13,127	)		(14,599	)
		(648,720	)		(516,793	)
Net deferred income taxes	$	1,281,833		$	1,299,082

At December 31, 2004, 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 2024.

16. 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, 2004, are entitled to upon involuntary bankruptcy is $30.3 million plus accrued dividends. The annual dividend requirements for all preferred securities outstanding at December 31, 2004, total $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 by the Secretary of State of the subsidiary’s electricity distribution license, was $56.0 million as of December 31, 2004 and 2003, respectively.

17. Convertible Preferred Stock

In connection with the Kern River acquisition and the purchase of $275.0 million of 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. 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. Each share of preferred stock is 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.

While the convertible preferred stock does not vote generally with the common stock in the election of directors, the convertible preferred stock gives Berkshire Hathaway the right to elect 20% of MEHC’s Board of Directors. The convertible preferred stock is convertible into common stock only upon the occurrence of specified events, including modification or elimination of the Public Utility Holding Company Act of 1935 so that holding company registration would not be triggered by conversion. Additionally, the prior approval of the holders of convertible preferred stock is 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.

MEHC’s Articles of Incorporation further provide that the convertible preferred shares: (a) are not mandatorily redeemable by MEHC or at the option of the holder; (b) participate in dividends and other distributions to common shareholders as if they were common shares and otherwise possess no dividend rights; (c) are convertible into common shares on a 1 for 1 basis, as adjusted for splits, combinations, reclassifications and other capital changes by MEHC; and (d) upon liquidation, except for a de minimus first priority distribution of $1 per share, shared ratably with the shareholders of common stock. Further, the aforementioned dividend and distribution arrangements cannot be modified without the positive consent of the preferred shareholders.

18. Stock Transactions

As of December 31, 2004, there were 2,048,329 options outstanding which are exercisable until the end of the term on March 14, 2008 at exercise prices ranging from $15.94 to $35.05 per share.

On March 6, 2002, MEHC purchased 800,000 stock options held by Mr. David L. Sokol, its Chairman and Chief Executive Officer. The options purchased had exercise prices ranging from $18.50 to $29.01. MEHC paid Mr. Sokol an aggregate amount of $27.1 million, which is equal to the difference between the option exercise prices and an agreed upon per share value.

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.

19. Accounting for Derivatives

The Company is exposed to market risk, including changes in the market price of certain commodities and interest rates. To manage the price volatility relating to these exposures, the Company enters into various financial derivative instruments. Senior management provide the overall direction, structure, conduct and control of the Company’s risk management activities, including the use of financial derivative instruments, authorization and communication of risk management policies and procedures, strategic hedging program and guidelines, appropriate market and credit risk limits, and appropriate systems for recording, monitoring and reporting the results of transactional and risk management activities.

Currency Exchange Rate Risk

CE Electric UK entered into currency rate swap agreements for its Senior Notes 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 outstanding at December 31, 2004. The agreements extend until maturity on December 30, 2007 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated fair value of these swap agreements at December 31, 2004 and 2003, was $35.7 million and $16.0 million, respectively, based on quotes from the counterparty to these instruments and represents the estimated amount that the Company would expect to pay if these agreement were terminated.

A subsidiary of CE Electric UK entered into 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 $281.1 million of the 6.496% Yankee Bonds outstanding at December 31, 2004. The agreements extend until maturity on February 25, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these swap agreements at December 31, 2004 and 2003, was $96.1 million and $62.6 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.

Derivatives

As of December 31, 2004, MidAmerican Energy held derivative instruments used for non-trading and trading purposes with the following fair values (in thousands):

Contract Type	Maturity in 2005			Maturity in 2006-08			Total
Non-trading:
Regulated electric assets	$	2,260		$	431		$	2,691
Regulated electric (liabilities)		(10,057	)		(4,817	)		(14,874	)
Regulated gas assets		2,973			1,798			4,771
Regulated gas (liabilities)		(21,921	)		-			(21,921	)
Regulated weather (liabilities)		(4,495	)		-			(4,495	)
Nonregulated electric assets		1,957			372			2,329
Nonregulated electric (liabilities)		(1,158	)		(214	)		(1,372	)
Nonregulated gas assets		5,937			1,919			7,856
Nonregulated gas (liabilities)		(6,606	)		(1,558	)		(8,164	)
Total		(31,110	)		(2,069	)		(33,179	)

Trading:
Nonregulated gas assets		993			-			993
Nonregulated gas (liabilities)		(430	)		(100	)		(530	)
Total		563			(100	)		463

Total MidAmerican Energy assets	$	14,120		$	4,520		$	18,640
Total MidAmerican Energy (liabilities)	$	(44,667	)	$	(6,689	)	$	(51,356	)

20. Regulatory Matters

MidAmerican Energy

Under three settlement agreements between MidAmerican Energy, The Iowa Office of Consumer Advocate (“OCA”) and other intervenors approved by the IUB, MidAmerican Energy has agreed not to seek a general increase in electric rates prior to 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 request or support 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.

The regulatory liabilities created by the three 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 in amounts equal to the AFUDC 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. As of December 31, 2004 and 2003, the related regulatory liability reflected in the accompanying consolidated balance sheets was $181.2 million and $144.4 million, respectively. The regulatory liability for 2011 will be credited to customer bills in 2012.

Kern River

Kern River was required to file a 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 a 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. Since its last rate case, Kern River has increased the capacity of its system from 724,500 Dth per day to 1,755,575 Dth per day at a cost of approximately $1.3 billion, resulting in a total rate base of approximately $1.8 billion. The rate increase became effective on November 1, 2004, subject to refund, and the FERC set a procedural order with a hearing scheduled for March 2005.

Northern Natural Gas

Additionally, on January 30, 2004, Northern Natural Gas filed with the FERC to increase its revenue requirement by an incremental $30 million to that requested in the May 1, 2003 filing. The increased revenue requirement is primarily attributable to ongoing pipeline integrity initiative costs that Northern Natural Gas has undertaken since the May 1, 2003 rate filing. The FERC suspended the rate increase until August 1, 2004 and consolidated the 2003 and 2004 rate cases due to the similarity of issues in both cases and the updated costs. On July 29, 2004, Northern Natural Gas notified the FERC that, in furtherance of settlement negotiations, Northern Natural Gas was not moving the rate increase into effect on August 1, 2004, but reserved its statutory right to move the suspended rates into effect at a later date. Northern Natural Gas’ implemented the new rates on November 1, 2004, subject to refund.

CE Electric UK

The majority of the revenue of the Distribution License Holder (“DLH”) in the United Kingdom is controlled by a distribution price control formula which is set out in the license of each DLH. It has been the practice of the Office of Gas and Electricity Markets (“Ofgem”) (and its predecessor body, the Office of Electricity Regulation), to review and reset the formula at five-year intervals, although the formula 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 United Kingdom’s competition authority, whose recommendation can then be given effect by license modifications made by Ofgem.

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 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.

21. 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 $71.1 million for 2004, $65.8 million for 2003, and $60.1 million for 2002. The minimum payments under these leases are $70.4 million, $64.3 million, $56.7 million, $45.9 million, and $33.0 million for the years 2005 through 2009, respectively, and $104.7 million for the total of the years thereafter.

MidAmerican Energy

Fuel, Energy and Operating Lease Commitments

MidAmerican Energy has supply and related transportation contracts for its fossil fueled generating stations. As of December 31, 2004, the contracts, with expiration dates ranging from 2005 to 2010, require minimum payments of $83.5 million, $67.4 million, $62.8 million, $22.0 million and $15.8 million for the years 2005 through 2009, respectively, and $15.5 million for the total of the years thereafter. 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 supply and transportation contract for a natural gas-fired generating plant. The contract, which expires in 2012, requires minimum annual payments of $6.2 million.

MidAmerican Energy also has contracts to purchase electric capacity. As of December 31, 2004, the contracts, with expiration dates ranging from 2005 to 2028, require minimum payments of $29.1 million, $25.1 million, $27.3 million, $35.8 million and $28.9 million for the years 2005 through 2009, respectively, and $73.9 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, 2004, the contracts, with expiration dates ranging from 2005 to 2013, require minimum payments of $54.2 million, $35.1 million, $25.2 million, $4.4 million and $2.9 million for the years 2005 through 2009, respectively, and $10.3 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, 2004, the maximum amount of such guarantees specified in these leases totaled $30.2 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 will hold 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, 2004 and 2003, totaled $152.3 million and $23.4 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 $59.9 million and $9.2 million, respectively, as of December 31, 2004 and 2003. MidAmerican Energy will bill each of the other owners for its share of the deferred payments when payment is made to Mitsui.

Air Quality

MidAmerican Energy’s generating facilities are subject to applicable provisions of the Clean Air Act and related air quality standards promulgated by the 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.

MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be required to meet emissions reductions as contemplated by the United States Environmental Protection Agency (“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 NO_X 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 Iowa Consumer Advocate Division of the Department of Justice. 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 $325.0 million, then MidAmerican Energy may seek to recover the additional expenditures from customers. At this time, MidAmerican Energy does not expect these capital expenditures to exceed such amount.

Nuclear Decommissioning Costs

Expected 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 decommissioning costs are included in base rates in Iowa tariffs.

MidAmerican Energy’s share of expected decommissioning costs for Quad Cities Station, in 2004 dollars, is $154.0 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 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. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability.

Exelon Generation purchases 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, 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 $5.0 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 purchased 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 purchased extra expense or business interruption 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 $8.8 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 in nuclear-related industries.

The current Price-Anderson Act expired in August 2002 and is pending congressional action for reauthorization. Its contingent financial obligations still apply to reactors licensed by the NRC as of its expiration date. It is anticipated that the Price-Anderson Act will be renewed with increased third party financial protection requirements for nuclear incidents.

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, LaPrairie Group Contractors (International) Ltd. (“LPG”), that MEHC’s 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, among others, CE Casecnan Ltd. and MEHC. On January 21, 2004, CE Casecnan Ltd. and LPG 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, totaling to $15.9 million, was set aside by CE Casecnan in an unsecured CE Casecnan account and is shown as restricted cash and short-term investments and other current liabilities in the accompanying consolidated balance sheet. The court is currently expected to rule on the first phase of the litigation before the end of the first quarter of 2005. The impact, if any, of this litigation on the Company cannot be determined at this time.

22. 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 participants’ compensation, years of service and age at retirement. 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.

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. Non-union employees hired July 1, 2004, and after will no longer be eligible for postretirement benefits other than pensions. The amendment establishes retiree medical accounts for participants to which the Company will make fixed contributions. 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.

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. 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.

	Pension Cost									Postretirement Cost
	2004			2003			2002			2004			2003			2002
	(in thousands)
Service cost	$	25,568		$	24,693		$	20,235		$	7,842		$	8,175		$	6,028
Interest cost		35,159			34,533			34,177			15,716			16,065			13,928
Expected return on plan assets		(38,258	)		(38,396	)		(38,213	)		(8,437	)		(6,008	)		(4,880	)
Amortization of net transition obligation		(792	)		(2,591	)		(2,591	)		3,283			4,110			4,110
Amortization of prior service cost		2,758			2,761			2,729			296			593			425
Amortization of prior year (gain) loss		1,569			1,483			(2,482	)		3,299			3,716			2,385
Regulatory expense		-			3,320			6,639			-			-			-
Net periodic benefit cost	$	26,004		$	25,803		$	20,494		$	21,999		$	26,651		$	21,996

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

	2004		2003		2002			2004		2003		2002
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:

	2004		2003		2002			2004		2003		2002
Discount rate	5.75	%	5.75	%	6.50	%		5.75	%	5.75	%	6.50	%
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:

	2004		2003
Health care cost trend rate assumed for next year	10.00	%	11.00	%
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

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	$	4,855	$	(3,740	)
Effect on postretirement benefit obligation	$	29,420	$	(24,066	)

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
		2004			2003			2004			2003
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year	$	551,568		$	467,773		$	157,849		$	122,655
Employer contributions		5,083			5,044			23,782			32,566
Participant contributions		-			-			7,733			6,371
Actual return on plan assets		63,151			105,438			9,698			15,853
Benefits paid		(28,174	)		(26,687	)		(19,687	)		(19,596	)
Fair value of plan assets at end of year	$	591,628		$	551,568		$	179,375		$	157,849

Reconciliation of benefit obligation:
Benefit obligation at beginning of year	$	620,048		$	593,179		$	297,433		$	291,441
Service cost		25,568			24,693			7,841			8,175
Interest cost		35,159			34,533			15,716			16,065
Participant contributions		-			-			7,733			6,371
Plan amendments		-			-			(19,219	)		-
Actuarial (gain) loss		4,805			(5,670	)		(33,773	)		(5,023	)
Benefits paid		(28,174	)		(26,687	)		(19,687	)		(19,596	)
Benefit obligation at end of year	$	657,406		$	620,048		$	256,044		$	297,433

Funded status	$	(65,778	)	$	(68,480	)	$	(76,669	)	$	(139,584	)
Amounts not recognized in consolidated balance sheets:
Unrecognized net (gain) loss		(34,319	)		(12,907	)		42,768			83,509
Unrecognized prior service cost		15,157			17,915			-			5,451
Unrecognized net transition obligation (asset)		-			(792	)		19,641			36,992
Net amount recognized in the consolidated balance sheets	$	(84,940	)	$	(64,264	)	$	(14,260	)	$	(13,632	)

Net amount recognized in the consolidated balance sheets consists of:
Prepaid benefit cost	$	-		$	39		$	-		$	-
Accrued benefit liability		(117,357	)		(100,490	)		(14,260	)		(13,632	)
Intangible assets		14,653			17,367			-			-
Regulatory assets		17,764			18,820			-			-
Net amount recognized	$	(84,940	)	$	(64,264	)	$	(14,260	)	$	(13,632	)

The portion of the pension projected benefit obligation, included in the table above, related to the supplemental executive retirement plan was $106.5 million and $105.1 million as of December 31, 2004 and 2003, respectively. The supplemental executive retirement plan has no assets, and accordingly, the fair value of its plan assets was zero as of December 31, 2004 and 2003. The accumulated benefit obligation for all defined benefit pension plans was $585.4 million and $554.6 million at December 31, 2004 and 2003, respectively. Of these amounts, the supplemental executive retirement plan accumulated benefit obligation totaled $102.3 million and $100.5 million for 2004 and 2003, respectively.

Although the supplemental executive retirement plan had no assets as of December 31, 2004, 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 cash surrender value of these assets is not included in the plan assets. The cash surrender value of the Rabbi trust investments was $98.8 million and $88.1 million at December 31, 2004 and 2003, 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 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 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, 2004 and 2003, are as follows:

	Percentage of
	Plan Assets
	at December 31					Target
		2004		2003			Range
Asset Category
Equity securities		71	%	70	%		65-75	%
Debt securities		22	%	23	%		20-30	%
Real estate		6	%	7	%		0-10	%
Other		1	%	-	%		0-5	%
Total		100	%	100	%

The Company’s postretirement benefit plan asset allocations at December 31, 2004, and 2003, are as follows:

	Percentage of
	Plan Assets
	at December 31					Target
		2004		2003			Range
Asset Category
Equity securities		49	%	49	%		45-55	%
Debt securities		47	%	48	%		45-55	%
Other		4	%	3	%		0-10	%
Total		100	%	100	%

Cash Flows

MidAmerican Energy’s expected benefit payments for its pension and postretirement plans for 2005 through 2009 and for the five years thereafter are summarized below (in thousands):

	Pension Benefits		Postretirement Benefits

2005	$	30,670	$	12,241
2006		32,728		11,731
2007		34,972		12,618
2008		38,092		13,432
2009		42,339		14,321
2010-14	$	267,549	$	87,264

Employer contributions to the domestic pension and postretirement plans are currently expected to be $6.6 million and $15.8 million, respectively, for 2005. 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. Total contributions were $17.1 million, $15.5 million and $12.0 million for 2004, 2003 and 2002, 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. The Medicare Act is expected to ultimately reduce the Company’s postretirement costs from what they would have been absent such changes. Detailed regulations pertaining to the Medicare Act were promulgated in July 2004, resulting in a $23.8 million reduction in the accumulated postretirement obligation, which has been reflected as an actuarial gain in the table above. The impact of the Medicare Act on the net periodic postretirement benefit expense will initially be recognized in 2005 in conjunction with the next valuation of the postretirement plans.

United Kingdom Operations

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

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

	Pension Cost
		2004			2003			2002
Service cost	$	12,100		$	9,485		$	8,718
Interest cost		73,515			62,632			56,817
Expected return on plan assets		(98,448	)		(89,124	)		(85,927	)
Amortization of prior service cost		1,915			1,472			1,202
Amortization of loss		12,742			537			-
Curtailment loss		-			-			6,463
Net periodic expense (benefit)	$	1,824		$	(14,998	)	$	(12,727	)

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

	2004		2003		2002
Discount rate	5.25	%	5.50	%	5.75	%
Rate of compensation increase	2.75	%	2.75	%	2.50	%

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

	2004		2003		2002
Discount rate	5.50	%	5.75	%	5.75	%
Expected return on plan assets	7.00	%	7.00	%	7.00	%
Rate of compensation increase	2.75	%	2.50	%	2.50	%

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):

	Pension Benefits
		2004			2003
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year	$	1,206,216		$	976,427
Employer contributions		17,600			14,391
Participant contributions		6,417			4,742
Actual return on plan assets		106,515			152,246
Benefits paid		(65,265	)		(57,726	)
Foreign currency exchange rate changes		93,239			116,136
Fair value of plan assets at end of year	$	1,364,722		$	1,206,216

Reconciliation of benefit obligation:
Benefit obligation at beginning of year	$	1,334,587		$	1,102,730
Service cost		12,100			9,485
Interest cost		73,515			62,632
Participant contributions		6,417			4,742
Benefits paid		(65,265	)		(57,726	)
Experience loss and change of assumptions		104,315			83,890
Foreign currency exchange rate changes		105,910			128,834
Benefit obligation at end of year	$	1,571,579		$	1,334,587

Funded status	$	(206,857	)	$	(128,371	)
Unrecognized net loss		614,182			507,039
Net amount recognized in the consolidated balance sheets	$	407,325		$	378,668

Amounts recognized in the consolidated balance sheets consist of:
Prepaid benefit cost	$	407,325		$	378,668
Accrued benefit liability		(561,988	)		(496,147	)
Intangible assets		16,119			16,604
Accumulated other comprehensive income		545,869			479,543
Net amount recognized	$	407,325		$	378,668

The accumulated benefit obligation for the defined benefit pension plan was $1.5 billion and $1.3 billion at December 31, 2004 and 2003, respectively.

The Company recorded a minimum pension liability as of December 31, 2004 and 2003 in the amount of $545.9 million and $479.5 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 2004 and 2003, as well as, mortality assumption changes which increased the liability. As of December 31, 2004 and 2003, 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, 2004 and 2003 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 $27.1 million in 2004 and 2003, 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.

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

	Percentage of
	Plan Assets
	at December 31,
		2004		2003		Target
Asset Category
Equity securities		49	%	64	%	50	%
Debt securities		39	%	26	%	40	%
Real estate		11	%	9	%	10	%
Other		1	%	1	%	-
Total		100	%	100	%	100	%

Cash Flows

CE Electric UK's expected benefit payments relative to the UK Plan for 2005 through 2009 and for the five years thereafter are summarized below (in millions):

2005	$	67.5
2006		67.0
2007		67.7
2008		68.1
2009		70.5
2010-14	$	369.8

Employer contributions to fund the ongoing liabilities of the UK Plan were approximately $14.7 million in 2004. The triennial process of valuing the UK Plan's assets and liabilities, which will value the plan assets and liabilities as of March 31, 2004, is underway. This valuation will set a revised level of contributions for the next three years. The preliminary report of the actuaries conducting the valuation showed a funding deficiency of $365.2 million. Based on the preliminary valuation, CE Electric UK has proposed that its subsidiaries contribute $63.6 million to the UK Plan each year, which amount includes $42.7 million 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. Discussions on the appropriate level of contributions continue with the UK Plan trustees in accordance with the UK Plan rules.

23. 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 and CalEnergy Generation-Foreign. 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 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 accompanying consolidated financial statements. Information related to the Company’s reportable segments is shown below (in thousands).

	Year Ended December 31,
		2004			2003			2002
Operating revenue:
MidAmerican Energy	$	2,701,700		$	2,600,239		$	2,240,879
Kern River		316,131			260,182			127,254
Northern Natural Gas		544,822			486,878			178,118
CE Electric UK		936,364			829,993			795,366
CalEnergy Generation-Foreign		307,395			326,454			326,316
CalEnergy Generation-Domestic		38,960			45,154			38,478
HomeServices		1,756,454			1,476,569			1,138,332
Total reportable segments		6,601,826			6,025,469			4,844,743
Corporate/other⁽¹⁾		(48,438	)		(59,839	)		(49,564	)
Total operating revenue	$	6,553,388		$	5,965,630		$	4,795,179

Depreciation and amortization:
MidAmerican Energy	$	266,409		$	281,001		$	269,412
Kern River		53,250			36,771			17,165
Northern Natural Gas		67,913			52,716			18,151
CE Electric UK		137,746			125,000			116,792
CalEnergy Generation-Foreign		90,328			87,928			88,036
CalEnergy Generation-Domestic		8,721			8,882			8,648
HomeServices		20,827			17,560			22,072
Total reportable segments		645,194			609,858			540,276
Corporate/other⁽¹⁾		(6,985	)		(6,924	)		(10,198	)
Total depreciation and amortization	$	638,209		$	602,934		$	530,078

Interest expense:
MidAmerican Energy	$	125,189		$	123,395		$	122,561
Kern River		76,671			79,272			47,034
Northern Natural Gas		53,100			56,008			23,550
CE Electric UK		202,067			180,207			189,554
CalEnergy Generation-Foreign		42,696			59,603			68,338
CalEnergy Generation-Domestic		18,971			19,736			20,043
HomeServices		2,837			3,864			4,256
Total reportable segments		521,531			522,085			475,336
Corporate/other⁽¹⁾		184,811			189,083			156,797
Parent company subordinated debt⁽²⁾		196,875			49,788			-
Total interest expense	$	903,217		$	760,956		$	632,133

	Year Ended December 31,
		2004			2003			2002
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income:
MidAmerican Energy	$	267,838		$	271,437		$	238,761
Kern River		142,643			133,720			60,700
Northern Natural Gas		217,981			127,307			42,882
CE Electric UK		325,844			288,720			266,755
CalEnergy Generation-Foreign		165,703			177,568			147,936
CalEnergy Generation-Domestic		3,071			2,120			(1,155	)
HomeServices		111,906			89,981			61,202
Total reportable segments		1,234,986			1,090,853			817,081
Corporate/other^{(1) (2)}		(435,793	)		(232,862	)		(185,443	)
Total income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income	$	799,193		$	857,991		$	631,638

Income tax expense:
MidAmerican Energy	$	87,336		$	110,078		$	99,782
Kern River		54,148			51,319			23,014
Northern Natural Gas		84,423			50,599			16,947
CE Electric UK		80,211			91,539			25,245
CalEnergy Generation-Foreign		62,548			62,130			31,924
CalEnergy Generation-Domestic		1,217			1,078			(4,611	)
HomeServices		52,996			43,587			28,207
Total reportable segments		422,879			410,330			220,508
Corporate/other⁽¹⁾		(157,893	)		(140,054	)		(109,230	)
Total income tax expense	$	264,986		$	270,276		$	111,278

Capital expenditures:
MidAmerican Energy	$	633,807		$	346,449		$	332,845
Kern River		26,936			433,125			692,586
Northern Natural Gas		138,747			104,400			62,409
CE Electric UK		334,458			301,896			222,622
CalEnergy Generation-Foreign		4,633			8,497			7,830
CalEnergy Generation-Domestic		1,341			6,619			(1,640	)
HomeServices		20,786			18,311			18,273
Total reportable segments		1,160,708			1,219,297			1,334,925
Corporate/other⁽¹⁾		18,682			71			7,373
Total capital expenditures	$	1,179,390		$	1,219,368		$	1,342,298

	As of December 31,
	2004			2003			2002

Total assets:
MidAmerican Energy	$	7,274,999		$	6,596,849		$	6,411,143
Kern River		2,135,265			2,200,201			1,797,850
Northern Natural Gas		2,200,846			2,167,621			2,162,367
CE Electric UK		5,794,887			5,038,880			4,714,459
CalEnergy Generation-Foreign		767,465			951,155			974,852
CalEnergy Generation-Domestic		553,741			1,113,172			1,145,456
HomeServices		724,592			567,736			488,324
Total reportable segments		19,451,795			18,635,614			17,694,451
Corporate/other⁽¹⁾		451,767			509,338			740,469
Total assets	$	19,903,562		$	19,144,952		$	18,434,920

Long-lived assets:
MidAmerican Energy	$	3,892,031		$	3,385,056		$	3,236,046
Kern River		1,945,094			1,976,213			1,650,387
Northern Natural Gas		1,491,428			1,430,475			1,403,748
CE Electric UK		3,691,459			3,227,723			2,741,277
CalEnergy Generation-Foreign		520,406			621,674			724,908
CalEnergy Generation-Domestic		256,429			738,296			739,940
HomeServices		59,827			53,518			45,078
Total reportable segments		11,856,674			11,432,955			10,541,384
Corporate/other⁽¹⁾		(249,410	)		(251,976	)		(256,897	)
Total long-lived assets	$	11,607,264		$	11,180,979		$	10,284,487

(1)	The remaining differences between the segment amounts and the consolidated amounts described as “Corporate/other” relate principally to the corporate functions including administrative costs, interest expense, corporate cash and related interest income, intersegment eliminations and 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 amounts previously recorded in minority interest and preferred dividends of subsidiaries to be recorded as interest expense in the accompanying consolidated statements of operations. For the year ended December 31, 2004, and the three-month period ended December 31, 2003, the Company has recorded $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 amounts included in minority interest and preferred dividends of subsidiaries related to these securities for the nine-month period ended September 30, 2003, and the year ended December 31, 2002, were $170.2 million and $147.7 million, respectively.

The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2004 and 2003 (in thousands):

	MidAmerican Energy	Kern River	Northern Natural Gas	CE Electric UK	Cal Energy Generation Domestic	Home- Services	Total
Balance, January 1, 2003	$2,149,282	$ 32,547	$ 414,721	$1,195,321	$126,440	$ 339,821	$4,258,132
Goodwill from acquisitions during the year	-	-	-	-	-	26,648	26,648
Other goodwill adjustments⁽¹⁾	(10,059)	1,353	(35,573)	66,262	(132)	(988)	20,863
Balance, December 31, 2003	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
Impairment losses⁽²⁾	-	-	-	-	(52,776)	-	(52,776)
Other goodwill adjustments⁽¹⁾	(18,098)	-	(24,236)	68,208	(1,038)	(3,072)	21,764
Balance, December 31, 2004	$2,121,125	$33,900	$354,912	$1,329,791	$72,494	$394,529	$4,306,751

(1)	Other goodwill adjustments include income tax, foreign currency translation and purchase price adjustments.

(2)	Impairment losses relate to the write-off of the Mineral Assets - see Note 3.

100

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, 2004. 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 significant changes during the fourth quarter of 2004 in the Company’s internal controls or in other factors that could significantly affect internal controls.

Item 9B. Other Information.

None.

101

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, Chief Executive Officer and Director
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
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
W. David Scott	Director
Edgar D. Aronson	Director
John K. Boyer	Director
Stanley J. Bright	Director
Richard R. Jaros	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 January 1, 2005, with respect to each of the foregoing officers and directors:

DAVID L. SOKOL, 48, 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, 42, 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 Price Waterhouse. As a Manager in the San Francisco office of Price Waterhouse, he was responsible for clients in the energy industry.

PATRICK J. GOODMAN, 38, Senior Vice President and Chief Financial Officer. Mr. Goodman joined MEHC in 1995 and served in various accounting positions including Senior Vice President and Chief Accounting Officer. Prior to joining MEHC, Mr. Goodman was a financial manager for National Indemnity Company and a senior associate at Coopers & Lybrand.

DOUGLAS L. ANDERSON, 46, Senior Vice President and General Counsel. Mr. Anderson joined MEHC in February 1993 and has served in various legal positions including General Counsel of the Company’s independent power affiliates. From 1990 to 1993, Mr. Anderson was a corporate attorney with Fraser, Stryker in Omaha, NE. Prior to that Mr. Anderson was a principal in the firm Anderson and Anderson.

KEITH D. HARTJE, 54, 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.

102

WARREN E. BUFFETT, 74, 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, the Gillette Company and The Washington Post Company.

WALTER SCOTT, JR., 73, 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 the past 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., ConAgra, Inc., Valmont Industries, Inc., Kiewit Materials Co., Commonwealth Telephone Enterprises, Inc. and RCN Corporation. Mr. Scott is the father of W. David Scott.

MARC D. HAMBURG, 55, 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.

W. DAVID SCOTT, 43, Director. Mr. Scott has been a director of MEHC since March 2000. Mr. Scott formed Magnum Resources, Inc., a commercial real estate investment and management company, in October 1994 and has served as its President and Chief Executive Officer since its inception. Before forming Magnum Resources, Mr. Scott worked for America First Companies, Cornerstone Banking Group and Peter Kiewit & Sons’, Inc. Mr. Scott has been a director of America First Mortgage Investments, Inc., a mortgage REIT, since 1998. Mr. Scott is the son of Walter Scott, Jr.

EDGAR D. ARONSON, 70, Director. Mr. Aronson has been a director of MEHC since 1983. Mr. Aronson founded EDACO, Inc., a private venture capital company, in 1981, and has been President of EDACO, Inc. since that time. Prior to that, Mr. Aronson was Chairman of Dillon, Read International from 1979 to 1981 and a General Partner in charge of the International Department of Salomon Brothers Inc. from 1973 to 1979. Mr. Aronson served during 1962-1968 as Vice President consecutively in the International Departments of First National Bank of Chicago and Republic National Bank of New York. He founded the International Department of Salomon Brothers and Hutzler in 1968.

JOHN K. BOYER, 60, Director. Mr. Boyer has been a director of MEHC since March 2000. He is a partner with Fraser, Stryker, Meusey, Olson, Boyer & Bloch, P.C. where he has practiced from 1973 to present with emphasis on corporate, commercial, federal, state, and local taxation.

STANLEY J. BRIGHT, 64, Director. Mr. Bright was Chairman and Chief Executive Officer of MidAmerican Energy from July 1, 1995 until March 1999. Mr. Bright joined Iowa-Illinois Gas and Electric Company (a predecessor of MidAmerican Energy) as Vice President and Chief Financial Officer in 1986, became a director in 1987, President and Chief Operating Officer in 1990, and Chairman and Chief Executive Officer in 1991.

RICHARD R. JAROS, 52, Director. Mr. Jaros has been a director of MEHC since March 1991. Mr. Jaros served as President and Chief Operating Officer of MEHC from January 8, 1992 to April 19, 1993 and as Chairman of the Board from April 19, 1993 to May 1994. Until July 1997, Mr. Jaros was Executive Vice President and Chief Financial Officer of Peter Kiewit & Sons’, Inc. and President of Kiewit Diversified Group, Inc., which is now Level 3 Communications, Inc. Mr. Jaros serves as director of Commonwealth Telephone Enterprises, Inc., RCN Corporation and Level 3 Communications, Inc.

Audit Committee Members and Financial Experts

The audit committee of the Board of Directors is comprised of Messrs. Marc D. Hamburg and Richard R. Jaros. The Board of Directors has determined that Messrs. Hamburg and Jaros qualify as “audit committee financial experts,” as defined by Securities and Exchange Commission Rules, based on their education, experience and background. Mr. Jaros is independent as that term is used in 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.

103

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, 2004, 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	2004	$	800,000	$	2,500,000	$	131,644	$	-	$	9,995
Chairman and Chief	2003		800,000		2,750,000		141,501		-		9,800
Executive Officer	2002		800,000		2,750,000		27,232,047		-		8,850

Gregory E. Abel	2004		720,000		2,200,000		80,424		-		9,995
President and	2003		700,000		2,200,000		87,162		-		9,800
Chief Operating Officer	2002		540,000		2,200,000		-		-		8,857

Patrick J. Goodman	2004		290,000		295,000		-		257,664		88,391
Senior Vice President and	2003		275,000		285,000		-		-		108,631
Chief Financial Officer	2002		248,000		260,000		209,970		-		(16,342	)

Douglas L. Anderson	2004		270,000		240,000		-		151,585		77,145
Senior Vice President and	2003		260,000		240,000		-		-		83,703
General Counsel	2002		200,000		220,000		-		-		(7,289	)

Keith D. Hartje	2004		180,000		65,000		-		128,847		54,774
Senior Vice President,	2003		180,000		65,000		-		-		71,317
Communications, General	2002		180,000		65,000		-		-		(3,015	)
Services and Safety Audit and
Compliance

______________

(1)	Includes amounts voluntarily deferred by the executive, if applicable.

(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 2004 for Mr. Sokol of $100,726 and for Mr. Abel of $73,859.

(3)

Consists of the 2004 earnings on the MEHC Long-Term Incentive Partnership Plan (“LTIP”) awards not paid out in 2004 and 401(k) plan contributions. For 2004, LTIP earnings on awards not paid out in 2004 were $78,396 for Mr. Goodman, $67,150 for Mr. Anderson and $44,979 for Mr. Hartje. Messrs. Sokol and Abel are not participants in the LTIP. Additionally, the amounts shown include company 401(k) contributions for 2004 for Messrs. Sokol, Abel, Goodman and Anderson of $9,995 and for Mr. Hartje of $9,795.

Pursuant to MEHC’s Executive Incremental Profit Sharing Plan, Messrs. Sokol and Abel are each eligible to receive a one-time profit sharing award of $11.25 million, $18.75 million or $37.5 million based upon achieving specified adjusted diluted earnings per share targets for any calendar year from 2004 through 2007 and continued employment during such time.

Option Grants in Last Fiscal Year

MEHC did not grant any options during 2004.

104

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, 2004.

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

David Sokol	-	-	1,399,277	-	$	113,073,927	N/A
Gregory E. Abel	-	-	649,052	-	$	55,748,672	N/A
Patrick J. Goodman	-	-	-	-		-	-
Douglas L. Anderson	-	-	-	-		-	-
Keith D. Hartje	-	-	-	-		-	-

______________

(1)	On March 14, 2000, MEHC was acquired by a private investor group. 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 stock of $113 per share as of December 31, 2004, as agreed to by MEHC stockholders.

Long-Term Incentive Plans - Awards in Last Fiscal Year

	Number of	Performance or
	Shares,	Other Period Until
	Units or Other	Maturation	Threshold	Target	Maximum
Name	Rights (#)	Or Payout	($) ⁽¹⁾	($) ⁽¹⁾	($) ⁽¹⁾

Patrick J. Goodman	N/A	December 31, 2008	40,000	N/A	N/A
Douglas L. Anderson	N/A	December 31, 2008	40,000	N/A	N/A
Keith D. Hartje	N/A	December 31, 2008	40,000	N/A	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 2004) 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

All directors, excluding Messrs. Sokol, Abel, Buffett and Walter Scott Jr., are paid an annual retainer fee of $24,000 and a fee of $500 per day for attendance at Board and Committee meetings. Directors who are employees are not entitled to receive such fees. All directors are reimbursed for their expenses incurred in attending Board meetings.

105

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, Goodman and Hartje 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 Company’s Named Executive Officers has or will have five years of credited service with the Company as of their respective normal retirement age 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, and by benefits under the Iowa Resources Inc. and Subsidiaries Supplemental Retirement Income Plan (the “IOR Supplemental Plan”), as applicable.

Part A of IOR Supplemental Plan provides retirement benefits up to sixty-five percent of a participant’s highest annual salary during the five years prior to retirement reduced by the participant’s MidAmerican Retirement Plan benefit. The percentage applied is based on years of credited service. A participant who elects early retirement is entitled to reduced benefits under the plan. A survivor benefit is payable to a surviving spouse. Benefits are adjusted annually for inflation. Part B of the IOR Supplemental Plan provides that an additional one hundred-fifty percent of annual salary is to be paid out to participants at the rate of ten percent per year over fifteen years, except in the event of a participant’s death, in which event the unpaid balance would be paid to the participant’s beneficiary or estate. Deferred compensation is considered part of the salary covered by the IOR Supplemental Plan.

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 each payroll period based upon a percentage of the participant’s salary paid in the current pay period. 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 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.

106

The table below shows the estimated aggregate 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. Subject to an annual renewal provision, such agreement is scheduled to expire on August 21, 2005.

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.

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 $10,650,000, $5,750,000 and $1,200,000, respectively, without giving effect to any tax related provisions.

107

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 January 31, 2005.

	Number of Shares	Percentage
Name and Address of Beneficial Owner ⁽¹⁾	Beneficially Owned⁽²⁾	Of Class⁽²⁾
Common Stock:
Walter Scott, Jr. ⁽³⁾	5,000,000	55.06	%
David L. Sokol ⁽⁴⁾	1,523,482	14.54	%
Berkshire Hathaway ⁽⁵⁾	900,942	9.92	%
Gregory E. Abel ⁽⁶⁾	704,992	7.25	%
W. David Scott ⁽⁷⁾	624,350	6.88	%
Douglas L. Anderson	-	-
Edgar D. Aronson	-	-
Stanley J. Bright	-	-
John K. Boyer	-	-
Warren E. Buffett ⁽⁸⁾	-	-
Patrick J. Goodman	-	-
Marc D. Hamburg ⁽⁸⁾	-	-
Richard R. Jaros	-	-
Keith D. Hartje	-	-
All directors and executive officers as a group (14 persons)	8,753,766	77.40	%

______________

(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)	Excludes 3 million 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.

(4)	Includes options to purchase 1,399,277 shares of common stock that are exercisable within 60 days.

(5)	Such beneficial owner’s address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.

(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)	Includes shares held by trusts for the benefit of or controlled by W. David Scott. Such beneficial owner’s address is 11422 Miracle Hills Drive, Suite 400, Omaha, Nebraska 68154.

(8)	Excludes 900,942 shares of common stock held by Berkshire Hathaway of which beneficial ownership of such shares is disclaimed.

The terms of MEHC’s Zero Coupon Convertible Preferred Stock held by Berkshire Hathaway entitle the holder thereof to elect two members of its Board of Directors. The Zero Coupon Convertible Preferred Stock does not vote as to the election of any other members of MEHC’s Board of Directors. 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 designate two additional directors.

108

Pursuant to a shareholders agreement, following March 14, 2003, Walter Scott, Jr. or any of the Scott Family Interests are able to require Berkshire Hathaway to purchase, for an agreed value or an appraised value, any or all of Walter Scott, Jr.’s and the Scott Family Interests’ shares of MEHC’s common stock, provided that Berkshire Hathaway is then a purchaser of a type which is able to consummate such a purchase without causing it or any of its affiliates or MEHC or any of its subsidiaries to become subject to regulation as a registered holding company or a subsidiary of a registered holding company under PUHCA. Berkshire Hathaway is not currently such a purchaser. The consummation of such a transaction could result in a change in control with respect to MEHC.

MEHC’s Amended and Restated Articles of Incorporation provide that each share of the Zero Coupon Convertible Preferred Stock is convertible at the option of the holder thereof into one conversion unit, which is one share of its common stock subject to certain adjustments as described in its articles, upon the occurrence of a Conversion Event. A “Conversion Event” includes (1) any conversion of Zero Coupon Convertible Preferred Stock that would not cause the holder of the shares of common stock issued upon conversion (or any affiliate of such holder) or the Company to become subject to regulation as a registered holding company or as a subsidiary of a registered holding company under PUHCA either as a result of the repeal or amendment of PUHCA, the number of shares involved or the identity of the holder of such shares and (2) a Company Sale. A “Company Sale” includes MEHC’s involuntary or voluntary liquidation, dissolution, recapitalization, winding-up or termination and mergers, consolidations or sale of all or substantially all of its assets. The conversion by Berkshire Hathaway of its shares of Zero Coupon Convertible Preferred Stock into MEHC’s common stock could result in a change in control with respect to beneficial ownership of its voting securities as calculated pursuant to Rule 13d-3(d) under the Securities Exchange Act.

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.

MEHC provided a guarantee in favor of a third party lender in connection with a $1,663,998.75 loan from such lender to its President, Gregory E. Abel, in March 2000. The loan matures on April 1, 2010. The proceeds of this loan were used by Mr. Abel to purchase 47,475 shares of MEHC’s common stock. Such common stock (together with 8,465 additional shares of common stock owned by Mr. Abel) also secures the loan. The entire original principal amount of the loan and the guarantee remain presently outstanding.

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.

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

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 “Certain Relationships and Related Transactions.”

109

Item 14. Principal Accountant Fees and Services.

Aggregate fees billed to the Company as a consolidated entity during the fiscal years ending December 31, 2004 and 2003 by the Company’s principal accounting firm, Deloitte & Touche LLP and the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte & Touche”), 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.

	Year Ended December 31,
	2004		2003
	(in millions)
Audit Fees ⁽¹⁾	$	3.2	$	2.6
Audit-Related Fees ⁽²⁾		0.1		0.3
Tax Fees ⁽³⁾		0.4		0.9
All Other Fees ⁽⁴⁾		-		-
Total aggregate fees billed	$	3.7	$	3.8

______________

(1)

Includes the aggregate fees billed for each of the last two fiscal years for professional services rendered by Deloitte & Touche 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 Deloitte & Touche 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 Deloitte & Touche 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.

(3)	Includes the aggregate fees billed in each of the last two fiscal years for professional services rendered by Deloitte & Touche 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 Deloitte & Touche, other than the services reported as “Audit Fees,” “Audit-Related Fees,” or “Tax Fees”.

The audit committee reviewed the non-audit services rendered by Deloitte & Touche in and for fiscal 2004 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.

110

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 112.
		See Schedule II on page 115.

		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.

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Schedule I

MidAmerican Energy Holdings Company

Parent Company Only

Condensed Balance Sheets

As of December 31, 2004 and 2003

(Amounts in thousands)

		2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	349,689		$	328,750
Investments in and advances to subsidiaries and joint ventures		6,141,843			5,731,915
Equipment, net		18,881			15,388
Goodwill		1,299,560			1,370,241
Deferred charges and other assets		168,805			180,331
Total assets	$	7,978,778		$	7,626,625

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and other liabilities	$	55,535		$	52,934
Current portion of senior debt		260,000			-
Current portion of subordinated debt		188,543			100,000
Total current liabilities		504,078			152,934
Other long-term accrued liabilities		35,142			31,298
Notes payable — affiliate		76,000			86,045
Senior debt		2,771,957			2,777,878
Subordinated debt		1,585,810			1,772,146
Total liabilities		4,972,987			4,820,301

Deferred income		30,229			32,916
Minority interest		4,403			1,963

Stockholders’ equity:
Zero coupon convertible preferred stock — authorized 50,000 shares, no par value; 41,263 shares outstanding		-			-
Common stock — authorized 60,000 shares, no par value; 9,081 and 9,281 shares issued and outstanding at December 31, 2004 and 2003, respectively		-			-
Additional paid in capital		1,950,663			1,957,277
Retained earnings		1,156,843			999,627
Accumulated other comprehensive loss, net		(136,347	)		(185,459	)
Total stockholders’ equity		2,971,159			2,771,445
Total liabilities and stockholders’ equity	$	7,978,778		$	7,626,625

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

112

Schedule I

MidAmerican Energy Holdings Company

Parent Company Only (continued)

Condensed Statements of Operations

For the three years ended December 31, 2004

(Amounts in thousands)

	2004			2003			2002

Revenues:
Equity in undistributed earnings of subsidiary companies and joint ventures	$	103,176		$	375,666		$	250,517
Dividends and distributions from subsidiary companies and joint ventures		330,678			318,665			351,847
Interest and other income		11,713			19,377			778
Total revenues		445,567			713,708			603,142

Costs and expenses:
General and administration		30,209			35,503			31,914
Depreciation and amortization		5,219			5,225			5,271
Interest, net of capitalized interest		399,394			247,509			164,290
Total costs and expenses		434,822			288,237			201,475
Income before income taxes		10,745			425,471			401,667
Income tax benefit		(159,461	)		(160,298	)		(126,043	)
Income before preferred dividends of subsidiaries		170,206			585,769			527,710
Preferred dividends of subsidiaries		-			170,151			147,667
Net income available to common and preferred stockholders	$	170,206		$	415,618		$	380,043

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

113

Schedule I

MidAmerican Energy Holdings Company

Parent Company Only (continued)

Condensed Statements of Cash Flows

For the three years ended December 31, 2004

(Amounts in thousands)

	2004			2003			2002

Cash flows from operating activities	$	(228,468	)	$	(230,354	)	$	(211,704	)

Cash flows from investing activities:
Decrease (increase) in advances to and investments in subsidiaries and joint ventures		116,167			228,083			(1,654,755	)
Other, net		6,803			(21,031	)		(2,840	)
Net cash flows from investing activities		122,970			207,052			(1,657,595	)
Cash flows from financing activities:
Purchase and retirement of common stock		(20,000	)		-			-
Repayment of subordinated debt		(100,000	)		(198,958	)		-
Proceeds from senior debt		249,765			449,295			700,000
Repayments of senior debt		-			(215,000	)		-
Proceeds from issuance of preferred stock		-			-			402,000
Proceeds from issuance of trust preferred securities		-			-			1,273,000
Net repayment of revolving credit facility		-			-			(153,500	)
Other		(3,328	)		(3,914	)		(34,096	)
Net cash flows from financing activities		126,437			31,423			2,187,404

Net change in cash and cash equivalents		20,939			8,121			318,105
Cash and cash equivalents at beginning of year		328,750			320,629			2,524
Cash and cash equivalents at end of year	$	349,689		$	328,750		$	320,629

Supplemental disclosures:
Interest paid, net of interest capitalized	$	392,390		$	219,910		$	164,267
Income tax receipts	$	(138,757	)	$	(135,025	)	$	(81,656	)

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

114

Schedule II

MIDAMERICAN ENERGY HOLDINGS COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

FOR THE THREE YEARS ENDED DECEMBER 31, 2004

(Amounts in thousands)

	Column B		Column C									Column E
	Balance at		Charged									Balance
Column A	Beginning		to		Other		Acquisition		Column D			at End
Description	of Year		Income		Accounts		Reserves ⁽²⁾		Deductions			of Year

Reserves Deducted From Assets To Which They Apply:

Reserve for uncollectible accounts receivable:
Year ended 2004	$	26,004	$	15,304	$	-	$	-	$	(15,275	)	$	26,033
Year ended 2003	$	39,742	$	13,620	$	-	$	-	$	(27,358	)	$	26,004
Year ended 2002	$	7,319	$	27,782	$	-	$	10,142	$	(5,501	)	$	39,742

Reserves Not Deducted From Assets^(1):
Year ended 2004	$	17,417	$	4,048	$	-	$	-	$	(10,617	)	$	10,848
Year ended 2003	$	10,981	$	10,527	$	-	$	-	$	(4,091	)	$	17,417
Year ended 2002	$	13,631	$	2,798	$	247	$	-	$	(5,695	)	$	10,981

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

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

(2)	Acquisition reserves represent the reserves recorded at Kern River and Northern Natural Gas at the date of acquisition.

115

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, in the City of Des Moines, State of Iowa, on this 28^th day of February 2005.

	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		Date

/s/ David L. Sokol*		February 28, 2005
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and Director

/s/ Gregory E. Abel*		February 28, 2005
Gregory E. Abel
President, Chief Operating Officer
and Director

/s/ Patrick J. Goodman*
Patrick J. Goodman		February 28, 2005
Senior Vice President and
Chief Financial Officer

/s/ Edgar D. Aronson*
Edgar D. Aronson		February 28, 2005
Director

/s/ Stanley J. Bright*
Stanley J. Bright		February 28, 2005
Director

/s/ Walter Scott, Jr.*
Walter Scott, Jr.		February 28, 2005
Director

/s/ Marc D. Hamburg*
Marc D. Hamburg		February 28, 2005
Director

/s/ Warren E. Buffett*
Warren E. Buffett		February 28, 2005
Director

116

Signature		Date

/s/ John K. Boyer*
John K. Boyer		February 28, 2005
Director

/s/ W. David Scott*
W. David Scott		February 28, 2005
Director

/s/ Richard R. Jaros*
Richard R. Jaros		February 28, 2005
Director


* By: /s/ Douglas L. Anderson
Douglas L. Anderson		February 28, 2005
Attorney-in-Fact

117

EXHIBIT INDEX

Exhibit No.

3.1	Amended and Restated Articles of Incorporation of MidAmerican Energy Holdings Company effective March 6, 2002 (incorporated by reference to Exhibit 3.3 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

3.2	Bylaws of MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 3.2 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A for the year ended December 31, 1999).

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	Registration Rights Agreement, dated as of October 1, 2002, by and between MidAmerican Energy Holdings Company and Credit Suisse First Boston (as Representative for the Initial Purchasers) (incorporated by reference to Exhibit 4.3 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

4.4	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).

4.5	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).

4.6	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).

4.7	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.)

4.8	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).

118

Exhibit No.

4.9	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).

4.10	Subscription Agreement, dated as of March 14, 2000, executed by Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.10 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	Subscription Agreement, dated as of March 7, 2002, executed by Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.12 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

4.13	Subscription Agreement, dated as of March 12, 2002, executed by Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.13 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

4.14	Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002 (incorporated by reference to Exhibit 4.14 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

4.15	Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002 (incorporated by reference to Exhibit 4.15 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

4.16	Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.16 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

4.17	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).

4.18	Subscription Agreement, dated as of August 16, 2002, executed by Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.18 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

4.19	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).

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).

119

Exhibit No.

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).

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 PNOC- 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 April 8, 1994, among CE Cebu Geothermal Power Company, Inc., the Banks thereto, Credit Suisse as Agent (incorporated by reference to Exhibit 10.96 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.9	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).

10.10	Pledge Agreement, dated as of April 8, 1994, among CE Philippines Ltd, Ormat-Cebu Ltd., Credit Suisse as Collateral Agent and CE Cebu Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.98 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.11	Overseas Private Investment Corporation Contract of Insurance, dated April 8, 1994, between the Overseas Private Investment Corporation and the Company through its subsidiaries CE International Ltd., CE Philippines Ltd., and Ormat-Cebu Ltd. (incorporated by reference to Exhibit 10.99 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.12	180 MW Power Plant-Mahanagdong Agreement, dated September 18, 1993, between PNOC- 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).

10.13	Credit Agreement, dated as of June 30, 1994, among CE Luzon Geothermal Power Company, Inc., American Pacific Finance Company, the Lenders party thereto, and Bank of America National Trust and Savings Association as Administrative Agent (incorporated by reference to Exhibit 10.101 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

120

Exhibit No.

10.14	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).

10.15	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).

10.16	Pledge Agreement, dated as of June 30, 1994, among CE Mahanagdong Ltd., Kiewit Energy International (Bermuda) Ltd., Bank of America National Trust and Savings Association as Collateral Agent and CE Luzon Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.104 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.17	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).

10.18	231 MW Power Plant-Malitbog Agreement, dated September 10, 1993, between PNOC- 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).

10.19	Credit Agreement, dated as of November 10, 1994, among Visayas Power Capital Corporation, the Banks parties thereto and Credit Suisse, as Bank Agent (incorporated by reference to Exhibit 10.107 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.20	Finance Agreement, dated as of November 10, 1994, between Visayas Geothermal Power Company and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.108 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.21	Pledge and Security Agreement, dated as of November 10, 1994, among Broad Street Contract Services, Inc., Magma Power Company, Magma Netherlands B.V. and Credit Suisse, as Bank Agent (incorporated by reference to Exhibit 10.109 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the year ended December 31, 1993).

10.22	Overseas Private Investment Corporation Contract of Insurance, dated December 21, 1994, between Overseas Private Investment Corporation and Magma Netherlands, B.V. (incorporated by reference to Exhibit 10.110 to MidAmerican Energy Holdings Company’s Annual Report on Form10-K for the year ended December 31, 1993).

10.23	Agreement as to Certain Common Representations, Warranties, Covenants and Other Terms, dated November 10, 1994, between Visayas Geothermal Power Company, Visayas Power Capital Corporation, Credit Suisse, as Bank Agent, Overseas Private Investment Corporation and the Banks named therein (incorporated by reference to Exhibit 10.111 to MidAmerican Energy Holdings Company’s 1994 Annual Report on Form 10-K for the year ended December 31, 1993).

10.24	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).

121

Exhibit No.

10.25	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).

10.26	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).

10.27	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).

10.28	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).

10.29	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).

10.30	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).

10.31	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).

10.32	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).

10.33	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).

10.34	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).

10.35	Sixth Amendment to 180 MW Power Plant-Mahanagdong Agreement, dated August 31, 2003, between PNOC-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).

122

Exhibit No.

10.36	Third Amendment to 231 MW Power Plant-Malitbog Agreement, dated August 31, 2003, between PNOC-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).

10.37	Seventh Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated August 31, 2003, between PNOC-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).

10.38	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).

10.39	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).

10.40	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).

10.41	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).

10.42	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).

10.43	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).

10.44	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).

10.45	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).

10.46	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).

10.47	Share Sale Agreement, dated as of August 6, 2001, among NPower Yorkshire Limited, Innogy Holdings plc, CE Electric UK plc and Northern Electric plc (incorporated by reference to Exhibit 10.63 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-101699 dated December 6, 2002).

123

Exhibit No.

10.48	Purchase Agreement, dated as of March 7, 2002, among The Williams Companies, Inc., Williams Gas Pipeline Company, LLC, Williams Western Pipeline Company LLC, Kern River Acquisition, LLC and MidAmerican Energy Holdings Company, KR Holding, LLC, KR Acquisition 1, LLC and KR Acquisition 2, LLC (incorporated by reference to Exhibit 99.2 to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated March 28, 2002).

10.49	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.)

10.50	Purchase and Sale Agreement, dated as of July 28, 2002, between Dynegy Inc., NNGC Holding Company, Inc. and MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 99.2 to MidAmerican Energy Holdings Company's Current Report on Form 8-K dated July 30, 2002).

10.51	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).

10.52	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).

10.53	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).

10.54	Fiscal Agency Agreement, dated as of May 4, 1993, among Northern Natural Gas Company, Enron Corp. and Continental Bank, National Association, Fiscal Agent, relating to the $100,000,000 in principal amount of the 6.875% Senior Notes due 2005 (incorporated by reference to Exhibit 10.68 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.55	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).

10.56	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).

10.57	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).

10.58	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).

124

Exhibit No.

10.59	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)

10.60	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).

10.61	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).

10.62	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).

10.63	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).

10.64	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).

10.65	First Supplemental Indenture, dated as of February 16, 2000, among Yorkshire Power Finance 2 Limited, Yorkshire Power Group Limited and The Bank of New York, Trustee, relating to the £155,000,000 in principal amount of the Reset Senior Notes due 2020 (incorporated by reference to Exhibit 10.79 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.66	Trust Agreement, dated as of February 1, 2000, among Yorkshire Power Group Limited, YPG Holdings LLC and The Bank of New York, Trustee, relating to the $250,000,000 in principal amount of the 8.25% Pass-Through Asset Trust Securities due 2005 (incorporated by reference to Exhibit 10.80 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.67	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).

125

Exhibit No.

10.68	Stock Redemption Agreement, dated as of January 8, 2004, between David L. Sokol and MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 10.82 to MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

10.69	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).

10.70	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.

10.71	MidAmerican Energy Holdings Company Amended and Restated Long-Term Incentive Partnership Plan dated as of January 1, 2004.

14.1	MidAmerican Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers.

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.

126