10-K/A 1 file001.htm AMENDMENT TO FORM 10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K/A

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

For the fiscal year ended December 31, 2003

Commission File No. 0-25551

MIDAMERICAN ENERGY HOLDINGS COMPANY

(Exact name of registrant as specified in its charter)

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

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 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.

Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Act). Yes No

All of the shares of common equity of MidAmerican Energy Holdings Company are held by a limited group of private investors. As of January 31, 2004, 9,081,087 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I


Item 1.	Business	4
Item 2.	Properties	33
Item 3.	Legal Proceedings	35
Item 4.	Submission of Matters to a Vote of Security Holders	37

PART II


Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	Selected Financial Data	38
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 8.	Financial Statements and Supplementary Data	56
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	100
Item 9A.	Controls and Procedures	100

PART III


Item 10.	Directors and Executive Officers of the Registrant	101
Item 11.	Executive Compensation	102
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	107
Item 13.	Certain Relationships and Related Transactions	108
Item 14.	Principal Accountant Fees and Services	109

PART IV


Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	110

EXPLANATORY NOTE

The Company originally filed its Annual Report on Form 10-K on February 9, 2004. In accordance with accounting guidance issued subsequent to that date, the Company is amending its originally filed Annual Report on Form 10-K to reflect the reclassification of 2002 and prior years' regulatory liabilities for the cost of removal of utility plant previously recognized within accumulated depreciation as an other long-term accrued liability. This amendment does not reflect events occurring after the original filing of the Form 10-K or modify or update those disclosures except as stated in the preceding sentence.

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.

MEHC 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") is a United States-based privately owned global energy company. The Company's operations 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 plc ("Northern Electric") and Yorkshire Electricity Group plc ("Yorkshire")), CalEnergy Generation – Domestic (interests in independent power projects and related operations), CalEnergy Generation – Foreign (the subsidiaries owning the Upper Mahiao, Malitbog and Mahanagdong projects (collectively, the "Leyte Projects") and the Casecnan project) and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). Refer to Note 20 in "Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements" 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 670,000 natural gas customers. Its natural gas pipeline subsidiaries operate interstate natural gas transmission systems with approximately 18,200 miles of pipeline in operation and peak delivery capacity of 6.2 billion cubic feet of natural gas per day. The Company has interests in 6,716 net owned megawatts of power generation facilities in operation and construction, including 5,142 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 comprised of 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 was 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, MMBtus means million British thermal units and Dth means decatherms or MMBtus.

MidAmerican Energy

Business

Through MidAmerican Energy, MEHC owns a public utility company headquartered in Iowa with $4.4 billion of assets as of December 31, 2003, and operating revenues for 2003 totaling $2.6 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. As of December 31, 2003, MidAmerican Energy had approximately 689,000 retail electric customers and 668,000 retail natural gas customers.

In addition to retail sales, MidAmerican Energy sells electric energy and natural gas to other utilities, marketers and municipalities. These sales are referred to as wholesale sales. It also transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas.

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, 2003, MidAmerican Energy derived approximately 54% of its gross operating revenues from its regulated electric business, 36% from its regulated gas business and 10% from its nonregulated business activities. For 2002 and 2001, the corresponding percentages were 61% electric, 31% gas and 8% nonregulated; and 56% electric, 37% gas and 7% nonregulated, respectively.

Electric Operations

The electric utility industry continues to undergo regulatory change. Traditionally, prices charged by electric utility companies have been regulated by federal and state commissions and have been based on cost of service. In recent years, changes have been occurring that move the electric utility industry toward a more competitive, market-based pricing environment. These changes may have a significant impact on MidAmerican Energy's business.

MidAmerican Energy manages its operations as four separate business units: generation, energy delivery, transmission, and marketing and sales. The generation segment derives most of its revenue from the sale of regulated wholesale electricity and non-regulated wholesale and retail natural gas. The energy delivery segment derives its revenue principally from the delivery of regulated electricity and natural gas, while the transmission segment obtains most of its revenue from the sale of electric transmission capacity. The marketing and sales segment receives its revenue principally from non-regulated sales of natural gas and electricity.

For the year ended December 31, 2003, regulated electric sales by MidAmerican Energy by customer class were as follows: 19.4% were to residential customers, 14.0% were to small general service customers, 25.4% were to large general service customers, 8.5% were to other customers, and 32.7% were wholesale sales. For the year ended December 31, 2003, regulated electric sales by MidAmerican Energy by jurisdiction were as follows: 88.8% to Iowa, 10.4% to Illinois and 0.8% 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 new

record hourly peak demand of 3,935 MW, which was 46 MW greater than MidAmerican Energy's previous record hourly peak demand of 3,889 MW set in July 2002.

The following table sets out certain information concerning MidAmerican Energy's power generation facilities based upon summer 2003 accreditation:


Operating Project ⁽¹⁾	Facility Net Capacity (MW)⁽²⁾		Net MW Owned⁽²⁾		Fuel		Location		Operation
Coal 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		708		368		Coal		Iowa		1981
Riverside Generation Station		135		135		Coal		Iowa		1925-61
Total coal facilities		3,960		2,865
Other Facilities:
Combustion Turbines		1,112		1,112		Gas/Oil		Iowa		1969-2003
Moline Water Power		3		3		Hydro		Illinois		1970
Quad Cities Generating Station		1,748		437		Nuclear		Illinois		1974
Portable Power Modules		56		56		Oil		Iowa		2000
Total other facilities		2,919		1,608

Accredited generating capacity		6,879		4,473
Projects Under Construction:
Greater Des Moines Energy Center ⁽³⁾		190		190		Gas		Iowa		2004
Council Bluffs Energy Center Unit 4		790		479		Coal		Iowa		2007
Total Power Generation Capacity		7,859		5,142


(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. 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 2003 as approved by the Mid-Continent Area Power Pool ("MAPP").


(3)	The Greater Des Moines Energy Center commenced commercial operations in May 2003. Since May 2003, 327 MW (included in "Other Facilities — Combustion Turbines" above) has been available.

MidAmerican Energy's accredited net generating capability in the summer of 2003 was 4,787 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 4,473 MW, generation under power purchase contracts of 630 MW and the net amount of capacity purchases and sales of (316) MW. The net generating capability at any time may be less than it would otherwise be due to regulatory restrictions, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling or modifications.

MidAmerican Energy anticipates a continuing increase in demand for electricity from its regulated customers. To meet anticipated demand and ensure adequate electric generation in its service territory, MidAmerican Energy is currently constructing two electric generating projects in Iowa and is developing a third. Upon completion, the projects will provide service to regulated retail electricity customers.

MidAmerican Energy has obtained regulatory approval to include the actual costs of the generation projects in its Iowa rate base as long as actual costs do not exceed an agreed upon cap that MidAmerican Energy has deemed to be reasonable. Wholesale sales may also be made from the projects to the extent the power is not needed for regulated retail service.

The first project is a natural gas-fired, combined cycle unit with an estimated cost of $357 million, excluding allowance for funds used during construction. MidAmerican Energy will own and operate the plant. Commercial operation of the simple cycle mode began on May 5, 2003. The plant, which will continue to be operated in simple cycle mode during 2004, resulted in 327 MW of accredited capacity in the summer of 2003. The combined cycle operation is expected to commence in December 2004 and achieve an expected additional accredited capacity of 190 MW.

The second project is currently under construction and will be 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 to be approximately $713 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 May 29, 2003, the Iowa Utilities Board ("IUB") issued an order that approves the ratemaking principles for the plant, and on June 27, 2003, MidAmerican Energy received a certificate from the IUB allowing MidAmerican Energy to construct the plant. 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. MidAmerican Energy is also seeking an order from the IUB approving construction of the associated transmission facilities.

The third project is currently under development and is comprised of wind power facilities totaling 310 MW based on the nameplate rating. Generally speaking, accredited capacity ratings for the 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. If constructed, MidAmerican Energy will own and operate these facilities, which are expected to cost approximately $323 million. MidAmerican Energy's plan to construct the wind project is in conjunction with a settlement agreement that extends through December 31, 2010, an Iowa retail electric rate freeze that was previously scheduled to expire at the end of 2005. The settlement agreement, which was filed with the IUB in conjunction with MidAmerican Energy's application for ratemaking principles for the wind project, was approved by the IUB on October 17, 2003. The obligation of MidAmerican Energy to construct the wind project may be terminated by MidAmerican Energy if the federal production tax credit applicable to the wind energy facilities is not available at a rate of 1.8 cents per kWh for a period of at least ten years after the facilities begin generating electricity. The production tax credit is available only to wind facilities placed in service before January 1, 2004. MidAmerican Energy has received authorization from the IUB to construct the wind power project. If MidAmerican Energy does not construct the wind facilities by December 31, 2007, the rate extension from January 1, 2006 through December 31, 2010 may terminate.

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 Mid-Continent Area Power Pool ("MAPP"). MAPP is a voluntary association of electric utilities doing business in Minnesota, Nebraska, North Dakota and the Canadian provinces of Saskatchewan and Manitoba and portions of Iowa, Montana, South Dakota and Wisconsin. Its membership also includes power marketers, regulatory agencies and independent power producers. MAPP facilitates operation of the transmission system, is responsible for the safety and reliability of the bulk electric system, and has responsibility for administration of 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. If a participant's capability reserve falls below the 15% minimum, significant penalties could be contractually imposed by MAPP. MidAmerican Energy's reserve margin at peak demand for 2003 was approximately 22%.

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. Refer to "Item 2. Properties" of this Form 10-K for additional information on transmission lines.

Gas Operations

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 regulatory assets by engaging in sales for resale transactions. IUB and South Dakota Public Utilities Commission rulings have allowed MidAmerican Energy to retain 50% of the respective jurisdictional margins earned on sales for resale 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. IUB and South Dakota Public Utilities Commission 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's cost of gas is recovered from customers through purchased gas adjustment clauses. In 1995, the IUB gave initial approval of MidAmerican Energy's Incentive Gas Supply Procurement Program. In November 2003, the IUB extended the program through October 31, 2004. 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.

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. In addition, MidAmerican Energy also utilizes three liquefied natural gas 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 addition, MidAmerican Energy has entered into various financial and physical gas purchase agreements to mitigate the volatility of gas prices during the winter heating season.

On February 2, 1996, MidAmerican Energy had its highest peak-day delivery of 1,143,026 MMBtus. This peak-day delivery consisted of approximately 88% traditional sales service and 12% transportation service of customer-owned gas. As of January 31, 2004, MidAmerican Energy's 2003/2004 winter heating season peak-day delivery of 1,093,294 MMBtus was reached on January 29, 2004. This peak-day delivery included approximately 73% traditional sales service and 27% transportation service.

Kern River

Business

Through Kern River, MEHC owns an interstate natural gas transportation pipeline system comprising 1,678 miles of pipeline, with an approximate design capacity of 1,755,626 Dth per day, extending from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California.

The 2003 Expansion Project

The 2003 Expansion Project, which was placed in service on May 1, 2003, increased the design capacity of Kern River's pipeline system by 885,626 Dth per day to its current 1,755,626 Dth per day. Kern River's pipeline is comprised 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 is comprised of the original 680 miles of 36-inch pipeline and 634.3 miles of 36-inch loop pipeline related to the 2003 Expansion Project.

The common facilities consist of a section of pipeline that extends from the point of interconnection with the mainline in Daggett to Bakersfield, California. The common facilities are jointly owned by Kern River (approximately 76.8 % as of December 31, 2003) and Mojave Pipeline Company ("Mojave"), a wholly owned subsidiary of El Paso Corporation (approximately 23.2% as of December 31, 2003), 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, 2003, Kern River had contracted 1,680,780 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 original mainline facilities, Kern River entered into 27 long-term firm gas transportation service agreements with 17 shippers, for a total of 864,154 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, Kern River entered into 19 long-term firm gas transportation service agreements with 17 shippers, for a total of 906,626 Dth per day of capacity from Opal, Wyoming to delivery points primarily in California, commencing May 1, 2003. Approximately 85% of the capacity of the 2003 Expansion Project was contracted for 15 years, with 14 of the long-term firm gas transportation service agreements expiring on April 30, 2018. The remaining 15% of capacity was contracted for 10 years, with five long-term firm gas transportation service agreements expiring on April 30, 2013. Over 95% of the capacity of the 2003 Expansion Project has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah.

Mirant Americas Energy Marketing ("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 the Mirant Agreement. In July 2003, Mirant filed for Chapter 11 bankruptcy protection and continued to use 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 $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 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 claim of $210.2 million, of which amount Kern River believes it

has a secured claim of $14.8 million. These claims arise from Mirant's rejection of the Mirant Agreement. Kern River is not presently able to provide a reasonable estimate as to how much it will ultimately recover on account of such claims.

On May 1, 2003, Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the approximately $815 million of outstanding borrowings under Kern River's $875 million credit facility entered into in 2002 to finance the construction of the 2003 Expansion Project.

Northern Natural Gas

Business

Through Northern Natural Gas, 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 in the United States as measured by pipeline miles and the eighth 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 is comprised 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 73% of Northern Natural Gas' firm transportation contracts extend beyond 2006.

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 approximately ten 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 2003, approximately 85% of Northern Natural Gas' revenue was from capacity charges under firm transportation and storage contracts and approximately 81% of that revenue was from LDCs. In 2003, approximately 70% 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 2003, approximately 21% 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 liquefied natural gas ("LNG") storage peaking unit at each of 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 2003, approximately 9% 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 both from 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 and Northern National 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 (the "Pipeline Safety Improvement Act") 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 competitive cost 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 Natural Gas Pipeline. 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 480 mmcf per day of volume on its system from such new facilities, of which approximately 465 mmcf per day is currently in service and approximately 15 mmcf per day is scheduled to begin service in 2004.

Pipeline Development Project

On January 22, 2004, MEHC and a recently formed subsidiary, Alaska Gas Transmission Company, LLC ("Alaska Gas"), filed an application with the State of Alaska Department of Revenue for approval under the Alaska Stranded Gas Development Act ("ASGDA") for authority to negotiate tax and financial terms with the State of Alaska to facilitate the transportation of stranded Alaskan natural gas. The proposed 745-mile, $6.3 billion pipeline, would be subject to FERC regulation and would extend from the North Slope area near Prudhoe Bay, Alaska southward to the Alaska-Yukon border near Beaver Creek, Alaska. On January 28, 2004, MEHC and Alaska Gas received notification from the Office of the Commissioner of the Department of Revenue of the State of Alaska that the proposed Alaska pipeline is a qualified project and Alaska Gas and its constituent owner-members constitute a qualified sponsor group, qualified to negotiate for favorable tax and financial terms as allowed under the ASGDA. MEHC, Alaska Gas, and two unaffiliated parties holding rights to acquire up to a combined aggregate of 19.9% of Alaska Gas's economic interest, intend to promptly commence negotiations with the State of Alaska.

CE Electric UK

Business

Through CE Electric UK, MEHC owns, primarily, two companies that distribute electricity in the United Kingdom, Northern Electric Distribution Limited ("NED") and Yorkshire Electricity Distribution plc ("YED").

In December 1996, CE Electric UK Ltd., an indirect wholly owned subsidiary of CE Electric UK, acquired Northern Electric. Northern Electric was one of the fifteen original United Kingdom regional electric companies that came into existence in 1990 as a result of the restructuring and subsequent privatization of the electricity industry that occurred in the United Kingdom. In September 2001, CE Electric UK acquired 94.75% of Yorkshire from Innogy Holdings plc ("Innogy") and simultaneously sold Northern Electric's electricity and gas supply and metering businesses to Innogy. The Company sometimes refers to these transactions as the "Yorkshire Swap". In August 2002, CE Electric UK acquired the remaining 5.25% of Yorkshire that it did not already own from Xcel Energy International ("Xcel"), an affiliate of Xcel Energy Inc.

With the acquisition of Yorkshire, CE Electric UK is one of the largest distribution companies in the United Kingdom, serving more than 3.7 million customers in an area of approximately 10,000 square miles.

A description of the functional business units of CE Electric UK is set forth below.

Electricity Distribution

Northern Electric's and Yorkshire's operations consist primarily of the distribution of electricity in the United Kingdom. Northern Electric's and Yorkshire's distribution licensee companies, NED and YED, respectively, 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 NED's and YED's distribution service areas are connected to the NED and YED networks and electricity can only be delivered through their distribution system, thus providing NED and YED with distribution volume that is relatively stable from year to year. NED and YED 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 NED's and YED's distribution networks pursuant to an industry standard "Use of System Agreement" which NED and YED separately entered into with the various suppliers of electricity in their respective distribution areas. One such supplier, Innogy plc. and certain of its affiliates, represented approximately 50% of the total revenues of NED and YED in 2003. The fees that may be charged by NED and YED for use of their distribution systems are controlled by a formula prescribed by the UK'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, 2003, NED's and YED's electricity distribution network (excluding service connections to consumers) on a combined basis included approximately 31,000 kilometers of overhead lines and approximately 63,000 kilometers of underground cables. In addition to the circuits referred to above, at December 31, 2003, NED's and YED's distribution facilities also included approximately 57,000 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 ("IUS"), a subsidiary of Northern Electric, is an engineering contracting company whose main business is providing electrical connection services on behalf of NED's and YED'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 subsidiary, is a gas exploration and production company that is focused on developing integrated upstream gas projects. Its

upstream gas business consists of the exploration, development and production, including transportation and storage, of gas for delivery to a point of sale into either a gas supply market or a power generation facility.

In May 2002, CE Gas completed the sale of substantially all of its United Kingdom natural gas assets to Gaz de France. In July 2003, CE Gas sold the ETS pipeline, which is a gas pipeline that extends from the North Sea to gas terminals in the United Kingdom, assets to CH4 Energy Limited. CE Gas retained its interest in the Victor Field, which is a gas field located in the North Sea. CE Gas also retained development interests in its Polish Trough project in Poland and its Bass, Otway and Perth Basins projects in Australia. In Poland, CE Gas, together with its joint venture partners FX Energy and the Polish Oil and Gas Company, is currently involved in drilling the Zaniemysl #3 well in the Fences Concession. The Bass development is a gas and gas liquids project in which CE Gas holds a 20% interest. The project, operated by Origin Energy of Australia, is under construction and includes an approximately 145 kilometer subsea pipeline across the Bass Strait off southern Victoria. The Bass project is expected to be fully operational during the fourth quarter of 2004. The gas from the project will be sold to Origin Energy's retail affiliate and the liquids to Elgas, the largest marketer of liquefied petroleum gas ("LPG") in Australia. The Otway project, in which CE Gas holds a 6% interest and which is operated by an unaffiliated party, is expected to receive construction approval during 2004 and offtake arrangements are being negotiated. In 2003, CE Gas acquired a one-third interest in Block LO2-6 in the northern Perth Basin, which is adjacent to the Dongara gas field. Arc Energy and Norwest Energy each also hold a one-third interest. The new permit is subject to satisfaction of the native title process, which is ongoing and expected to be completed by late 2004, at which time exploration activities can commence. In May 2003, CE Gas withdrew from all its southern Perth Basin permits.

CalEnergy Generation – Domestic

Business

Through CalEnergy Generation – Domestic, the Company owns 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, 2003:

Operating Project

Facility Net
Capacity
(MW)⁽¹⁾

Net MW
Owned⁽¹⁾

Fuel

Location

Power
Purchase
Agreement
Expiration

Power Purchaser⁽²⁾

Cordova

537

Gas

Illinois

2017

El Paso/
MidAmerican Energy

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

TransAlta/Minerals

Riverside⁽³⁾

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

TransAlta/Minerals⁽³⁾

Saranac

240

Gas

New York

2009

NYSE&G

Power Resources⁽⁴⁾

212

106

Gas

Texas

2005

ONEOK

Yuma

Gas

Arizona

2024

SDG&E

Roosevelt Hot Springs⁽⁵⁾

Geo

Utah

2020

UP&L

Domestic Operating Projects

1,389

939


(1)	Represents nominal net generating capability (accredited for Cordova and contract for most others). Actual MW may vary depending on operating 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 Corporation ("El Paso"); Southern California Edison Company ("Edison"); TransAlta USA Inc. ("TransAlta"); CalEnergy Minerals LLC ("Minerals"); the City of Riverside, California ("Riverside"); 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").

(3)

Each contract governing power purchases by Minerals will expire 33 years from the date of the initial power delivery under such contract. Pursuant to a Transaction Agreement dated January 29, 2003, Salton Sea Power LLC ("Salton Sea Power") which owns Salton Sea V, and CE Turbo LLC ("CE Turbo") began selling available power to a subsidiary of 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 or (b) any other termination date mutually agreed to by the parties. No such notice of termination has been given by either party. Effective July 1, 2004, Salton Sea Power and CE Turbo will also be selling the environmental attributes associated with up to 931,800 MWh to TransAlta Energy Marketing (US) Inc., an affiliate of TransAlta, through December 31, 2008. Salton Sea Power also entered into a 10-year power sales agreement for up to 20 MW with Riverside in May 2003.

(4)

Power Resources net capacity was 200 MW during operation as a qualifying facility ("QF") within the meaning of the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA") under the TXU Power Generation Company, LP ("TXU") Power Purchase Agreement, which expired September 30, 2003. The net capacity increased to 212 MW during operations as an exempt wholesale generator ("EWG"), as defined by the Energy Policy Act of 1992, under the ONEOK tolling agreement due to the absence of the need to deliver steam to a third party.


(5)	Intermountain Geothermal Company, an indirect subsidiary of MEHC, owns an approximately 70% indirect interest in this project which supplies geothermal steam to a power plant owned by UP&L. 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 this steam field.

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. Cordova Energy has exercised an option to recall from El Paso 50% of the output through May 14, 2004, reducing El Paso's purchase obligation to 50% of the output during such period. The recalled output is being sold to MidAmerican Energy. 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, which is subject to the agreement. The power purchase agreements provide for energy payments, capacity payments and capacity bonus 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 was fixed for the life of the SO4 Agreements and is significantly higher in the months of June through September.

Energy payments for the SO4 Agreements were at increasing fixed rates for the first ten years after firm operation and thereafter at a rate 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, 2003, 2002 and 2001, respectively, Edison's Average Avoided Cost of Energy was 5.4 cents per kWh, 3.5 cents per kWh and 7.4 cents per kWh, respectively. Estimates of Edison's future Avoided Cost of Energy vary substantially from year to year.

The Salton Sea V project, which commenced operations in the third quarter of 2000, sells up to 22 MW of its net output to Minerals, pursuant to a 33-year power sales agreement. The agreement provides for energy payments based on the market rates available to the Salton Sea V project, adjusted for wheeling costs. On May 20, 2003, 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. The Salton Sea V project sells its remaining output through other market transactions.

The CE Turbo project, which commenced commercial operation in the third quarter of 2000, sells its output through market transactions. The CE Turbo project may sell its output to Minerals, pursuant to a 33-year power purchase agreement. The agreement provides for energy payments based on the market rates available to the CE Turbo project, adjusted for wheeling costs.

Salton Sea Power and CE Turbo began selling power to a subsidiary of TransAlta on February 12, 2003 based on percentages of Dow Jones SP-15 Index. The Transaction Agreement shall continue until the earlier of (a) 30 days following a written notice of termination by either party or (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. The power purchase agreement, the steam purchase agreement and the gas supply agreement contain rates that are fixed for the respective contract terms and expire in 2009.

The Power Resources project, a 212 net MW natural gas-fired cogeneration project owned by Power Resources Ltd. ("Power Resources"), an indirect wholly-owned subsidiary of CE Generation, sold electricity to TXU, as a QF under PURPA, pursuant to a power purchase agreement which expired on September 30, 2003. The Power Resources project sold steam to ALON USA, LP under a 15-year agreement that also expired September 30, 2003.

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 EWG, sells its energy 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 providing 50 MW of electricity to SDG&E under an existing 30-year power purchase contract commencing in May 1994. The project entity, Yuma Cogeneration Associates, 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

MEHC's indirectly wholly owned subsidiary, Minerals, developed and owns the rights to proprietary processes for the extraction of zinc from elements in solution in the geothermal brine and fluids utilized at the Imperial Valley Projects. The affiliates of Minerals may develop facilities for the extraction of manganese, silica and other products as they further develop the extraction technology.

Minerals constructed the Zinc Recovery project, which is recovering zinc from the geothermal brine. Facilities have been installed near the sites of the Imperial Valley Projects to extract a zinc chloride solution from the geothermal brine through an ion exchange process. This solution is being transported to a central processing plant where zinc ingots are produced through solvent extraction, electrowinning and casting processes. The Zinc Recovery project began limited production during December 2002 and continued limited production during 2003. Minerals entered into a sales agreement whereby all high-grade zinc produced by the Zinc Recovery project will be sold to Cominco, Ltd. at prevailing market prices. The agreement expires in December 2005.

Development Projects

MEHC's 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. On December 17, 2003, the California Energy Commission ("CEC") gave final approval for construction of the facility.

CalEnergy Generation – Foreign

Business

The CalEnergy Generation – Foreign platform consists of MEHC's indirect ownership of the Upper Mahiao, Malitbog and Mahanagdong 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, 2003:


Project⁽¹⁾	Facility Net Capacity (MW)⁽²⁾		Net MW Owned⁽²⁾		Fuel		Commercial Operation		Power Purchaser/ Guarantor⁽³⁾
Upper Mahiao		119		119		Geo		1996		PNOC-EDC/ROP
Mahanagdong		155		150		Geo		1997		PNOC-EDC/ROP
Malitbog		216		216		Geo		1996-97		PNOC-EDC/ROP
Casecnan⁽⁴⁾		150		150		Hydro		2001		NIA/ROP
International Projects		640		635


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


(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 — Philippines — CE Casecnan Stockholder Litigation."

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 the 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, the government-owned and controlled corporation that is the primary supplier of electricity in the Philippines ("NPC"), 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 approximately 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-dominated 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 government of the Philippines 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.

CE Casecnan owns and operates the Casecnan project, 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 water tunnel. A tailrace discharge tunnel delivers water to the Pantabangan reservoir, 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 amended by a Supplemental Agreement between CE Casecnan and NIA signed in September 2003 and 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.

Under the terms of the Project Agreement, NIA had the option of timely reimbursing CE Casecnan directly for certain taxes CE Casecnan paid. If NIA did not so reimburse CE Casecnan, certain taxes paid by CE Casecnan would have resulted in an increase in the Water Delivery Fee (refer to the Amended and Restated CE Casecnan Project Agreement or the Supplemental Agreement for a definition of each capitalized term used in this section that is not otherwise defined in this report). The payment of certain other taxes by CE Casecnan would have resulted automatically in an increase in the Water Delivery Fee. Since the inception of the project and continuing through the commencement of commercial operations, NIA had failed to reimburse CE Casecnan for those taxes and also had failed to pay the portion of the Water Delivery Fee each month related to the payment of these taxes by CE Casecnan. As a result of the non-payment of the tax compensation portion of the Water Delivery Fees, on August 19, 2002, CE Casecnan filed a Statement of Claim against NIA pursuant to the Rules of Arbitration of the ICC (the "NIA Arbitration"), seeking payment of such portion of the Water Delivery Fee and enforcement of the relevant provision of the Project Agreement going forward.

On October 15, 2003, pursuant to the Supplemental Agreement, all claims by CE Casecnan and counterclaims by NIA in the NIA Arbitration were dismissed with prejudice and the terms of the Project Agreement were modified and supplemented in certain respects. Summarized below are significant provisions of the Project Agreement as supplemented by the Supplemental Agreement.

Under the Project 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, NIA is obligated to pay CE Casecnan an amount for the delivery of water equal to the sum of the Guaranteed Water Delivery Fee plus the Variable Delivered Water Delivery Fee minus the Water Delivery Fee Credit. For the sixty-month period from December 25, 2003 through December 25, 2008, the Guaranteed Water Delivery Fee shall equal $0.029 per cubic meter, escalated at 7.5% annually from January 1, 1994 through December 25, 2006 (the "Guaranteed Water Delivery Rate") multiplied by approximately 66.8 million cubic meters per month (corresponding to the 801.9 million cubic meters per year), regardless of actual water deliveries made by the Casecnan project. For each month beginning after December 25, 2008 through the remainder of the Cooperation Period, the Guaranteed Water Delivery Fee shall equal the Guaranteed Water Delivery

Rate multiplied by approximately 58.3 million cubic meters (corresponding to 700.0 million cubic meters per year), regardless of actual water deliveries made by the Casecnan project.

The Variable Delivered Water Delivery Fees are payable for each month beginning after December 25, 2008 through the end of the Cooperation Period, but only from the date when the cumulative Total Available Water (total delivered water plus the water volume not delivered to NIA as a result of NIA's failure to accept energy deliveries at a capacity up to 150 MW) for each contract year exceeds 700.0 million cubic meters. Variable Delivered Water Delivery Fees will be earned up to an aggregate maximum of 1,324.7 million cubic meters for the period from December 25, 2008 through the end of the Cooperation Period. No additional variable water delivery fees will be earned over the 1,324.7 million cubic meter threshold.

The Water Delivery Credit shall be applicable only for each of the sixty-months from December 25, 2008 through December 25, 2013 and shall equal the Water Delivery Rate as of December 25, 2008 multiplied by the sum of each Annual Water Credit divided by sixty. The Annual Water Credit for each contract year starting from December 25, 2003 and ending on December 25, 2008 shall equal 801.9 million cubic meters minus the Total Available Water for each contract year. The Total Available Water in any such year will equal actual deliveries with a minimum threshold of 700.0 million cubic meters.

With respect to electricity, CE Casecnan is paid a Guaranteed Energy Delivery Fee each month equal to the product obtained by multiplying 19,000,000 kWh 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 19,000,000 kWh 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 490,000,000 kWh but less than 550,000,000 kWh per year are paid for at a rate of 1.3 Philippine pesos per kWh and deliveries in excess of 550 GWh per year are at no cost to NIA. 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 entering into the Supplemental Agreement, on October 15, 2003, NIA paid to CE Casecnan the sum of $17.7 million plus 39.9 million pesos (approximately $0.7 million) and delivered to CE Casecnan the 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. Also pursuant to the Supplemental Agreement, CE Casecnan paid to the Philippine Bureau of Internal Revenue ("BIR") approximately $24.4 million in respect of Philippine income taxes on the foregoing consideration and CE Casecnan paid to NIA $1.6 million in respect of alleged late completion of the Casecnan project.

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.

As part of the settlement of the NIA Arbitration, CE Casecnan also 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, which authorized the ROP to seek to renegotiate certain contracts such as the Project Agreement, have been satisfactorily addressed by the Supplemental Agreement.

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, title and closing services and other related services. HomeServices currently operates in 16 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, 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; Des Moines, Iowa; Omaha and Lincoln, Nebraska; Birmingham and Auburn, Alabama; Tucson, Arizona; Louisville and Lexington, Kentucky; Annapolis, Maryland; Atlanta, Georgia; Miami, Florida and Springfield, Missouri.

Acquisitions

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. 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 has sufficient low cost 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.

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.

In response to Order No. 2000, MidAmerican Energy and five other electric utilities applied for FERC approval to create TRANSLink Transmission Company LLC ("TRANSLink") as a for-profit independent transmission company to be operated in conjunction with a FERC-approved RTO. The FERC approved that application in April 2002. In June 2003, the IUB issued an order disapproving MidAmerican Energy's application for state regulatory approval of MidAmerican Energy's participation in TRANSLink and inviting MidAmerican Energy to refile the application once certain issues at the federal level have been resolved. On November 21, 2003, in response to continued regulatory uncertainty, TRANSLink suspended its operations and dissolved its interim management team. MidAmerican Energy is currently evaluating options relating to its transmission options in light of TRANSLink's current status.

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 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. Legislation that is currently pending in Congress would forbid the FERC from implementing the SMD rule for several years, but it is not certain whether that legislation will be adopted. Any final rule on SMD may impact the costs of MidAmerican Energy's electricity and transmission products. A final rule on SMD could directly or indirectly influence how transmission services are priced, the availability of transmission services, and how transmission services are obtained. In addition, the rule could affect how wholesale electricity is bought and sold, as well as the geographic scope of the wholesale marketplace in which MidAmerican Energy buys and sells electricity. MidAmerican Energy recognizes there is considerable uncertainty as to the timing and outcome of this rulemaking and will continue to evaluate the status of the adoption of SMD for the wholesale markets. Transferring the operations and control of MidAmerican Energy's transmission assets to other entities could increase costs for MidAmerican Energy; however, the actual effect of any such transaction on MidAmerican Energy's future transmission costs, or alternate RTO strategies, is not yet known.

Under two settlement agreements approved by the IUB, MidAmerican Energy's Iowa retail electric rates in effect on December 31, 2000, are effectively frozen through December 31, 2010. The settlement agreements specifically allow the filing of electric rate design or cost of service rate changes that are intended to keep MidAmerican Energy's overall Iowa retail electric revenue unchanged, but could result in changes to individual tariffs. 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 to be used to offset a portion of the cost to Iowa customers of future generating plant investment.

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. An amount equal to the regulatory liability is recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. Future depreciation will be reduced as a result of the credit applied to generating plant balances as the regulatory liability is reduced. The liability is being reduced as it is credited against plant in service in amounts equal to the allowance for funds used during construction associated with generating plant additions. Interest expense is accrued on the portion of the regulatory liability related to prior years.

The 2003 settlement agreement also provides that if Iowa retail electric returns on equity fall below 10% in any consecutive 12-month period after January 1, 2006, MidAmerican Energy may seek to file for a general increase in rates. However, prior to filing for a general increase in rates, MidAmerican Energy is required by the settlement agreement to conduct 30 days of good faith negotiations with all of the signatories to the settlement agreement to attempt to avoid a general increase in rates.

Illinois bundled electric rates are frozen until 2007, subject to certain exceptions allowing for increases, at which time bundled rates are subject to cost-based ratemaking. Illinois law provides for Illinois earnings above a computed level of return on common equity 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 2003 was 13.73%. The law allows MidAmerican Energy to mitigate the sharing of earnings above the threshold return on common equity through accelerated recovery of electric assets.

On November 8, 2002, the IUB approved a gas rate settlement agreement previously filed with it by MidAmerican Energy and the Iowa Office of Consumer Advocate. The settlement agreement provided for an increase in rates of $17.7 million annually for MidAmerican Energy's Iowa retail natural gas customers and effectively froze base rates through November 2004. However, MidAmerican Energy will continue collecting fluctuating gas costs through its purchased gas adjustment clause. The new rates were implemented for usage beginning November 25, 2002.

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 Department of Transportation pursuant to the Natural Gas Pipeline Safety Act, 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. Its pipeline subsidiaries also are required to file with the FERC an annual report on Form 2, which is publicly available, disclosing general corporate information and financial statements regarding its pipeline subsidiaries.

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.

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 filing provides evidence in support of a $71 million increase to Northern Natural Gas' annual revenue requirement. However, Northern Natural Gas is requesting that only $55 million of this increase be effectuated. Northern Natural Gas' new rates went into effect November 1, 2003, subject to refund. Additionally, Northern Natural Gas filed on January 30, 2004 with the FERC to increase its revenue requirement by an incremental $30 million to that requested in the May 1, 2003 filing. Northern Natural Gas requested that the new rates be effective commencing August 1, 2004. Northern Natural Gas has filed to consolidate the two rate proceedings, but the FERC has not yet ruled on Northern Natural Gas' motion.

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

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 QFs 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. Congress is currently considering major changes to both PUHCA and PURPA. Any such legislation, if adopted, could vary considerably from the terms which are presently under consideration. MEHC believes that if the current proposed legislation is passed, it would apply to new projects only and thus, although potentially impacting its ability to develop new domestic projects, it would not affect MEHC's existing qualifying facilities. MEHC cannot provide assurance, however, that legislation, if passed, or any other similar legislation proposed in the future, would not adversely impact its 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 MEHC'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 MEHC'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 MEHC 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, MEHC 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 those in which MidAmerican Energy has an ownership interest, such as the Quad Cities units, and additional such expenditures could be required in the future.

Pipeline Safety Regulation

The Company's pipeline operations are subject to regulation by the United States Department of Transportation ("DOT") under the Natural Gas Pipeline Safety Act of 1968 ("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 deemed 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 Pipeline Safety Improvement Act requires major new programs in the areas of operator qualification, risk analysis and integrity management. The Act 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 this Act, 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.

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 and Yorkshire 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, Northern Electric and Yorkshire (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 Northern Electric and Yorkshire were transferred to NED and YED, respectively. NED and YED 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 Northern Electric's electricity and gas supply business to Innogy and the retention by Innogy of the electricity and gas supply business of Yorkshire, all as a part of the Yorkshire Swap (an agreement to exchange Northern Electric's electricity and gas supply and metering assets for Innogy's 94.75% interest in Yorkshire's electricity distribution business) on September 21, 2001.

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

Most revenue of the DLHs 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 U.K.'s competition authority.

The periodic review during which the formula is reset is the process by which Ofgem determines its view of the future allowed revenue of DLHs. The procedure and methodology adopted at a price control review is at the reasonable discretion of Ofgem. At the last such review, concluded in 1999 and effective April 2000, Ofgem's judgment of the future allowed revenue of licensees was 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 licensee;


•	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 last review, the allowed revenue of NED's distribution business was reduced by 24%, in real terms, and the allowed revenue of YED's distribution business was reduced by 23%, in real terms, with effect from April 1, 2000. The range of reductions for all licensees in Great Britain was between 4% and 33%.

For the duration of the current regulatory period, the 1999 review also requires that regulated distribution revenue per unit be increased or decreased each year by RPI-Xd, where the factor "RPI" is the United Kingdom retail price index reflecting the average of the 12-month inflation rates recorded for each month in the previous July to December period and "Xd" is an adjustment factor which was established by Ofgem at the 1999 review (and continues to be set) at 3%. The formula also takes account of the changes in system electrical losses, the number of end users connected and the voltage at which end users receive the units of electricity distributed. This formula determines the maximum average price per unit of electricity distributed (in pence per kWh) which a DLH is entitled to charge the suppliers of electricity, which are the DLH's customers. The distribution price control formula permits DLHs to receive additional revenue due to increased distribution of units and a predetermined increase in end users. Once set, the price control formula does not, during its duration, 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. Therefore during the duration of the price control, increases or decreases in costs, if any, directly impact profit.

Ofgem has commenced the process of reviewing each DLH's existing price control formula, with a revised formula for each DLH (including NED and YED) expected to take effect from April 1, 2005 for an expected period of five years. In April 2002, Ofgem modified the licenses of all DLHs to implement an "Information and Incentives Project" under which up to 2% of a DLH's regulated income depends upon the performance of the DLH's distribution system as measured by the number and duration of customer interruptions and upon the level of customer satisfaction monitored by Ofgem.

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 – 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 an EWG is not considered to be an electric utility company. An 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.

CalEnergy Generation – Foreign

The Philippine Congress has passed the Electric Power Industry Reform Act of 2001 ("EPIRA"), which is aimed at restructuring the Philippine power industry, privatizing the NPC and introducing a competitive electricity market, among other initiatives. The implementation of EPIRA may have an impact on MEHC'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. In connection with the settlement of the NIA Arbitration and 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. The Company'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, MEHC 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.

CE Casecnan representatives, together with certain current and former government officials, also were requested to and did appear, during 2002 and the first half of 2003, before a Philippine Senate committee which had raised questions and made allegations with respect to the Casecnan project's tariff structure and implementation. The Company believes that as a result of the settlement of the NIA Arbitration and the entering into of the Supplemental Agreement the questions and allegations raised by the Philippine Senate committee have been addressed, although there can be no assurance that additional inquiries by the Philippine Congress or any agency of the Philippine government will not be made in the future.

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. 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 final rule, if adopted as currently proposed, would require HomeServices to substantially change the manner in which mortgage, title insurance and escrow closing services are marketed and delivered to consumers. Title insurance and escrow closing services, in particular, may be marketed to lenders for inclusion within a lender's guaranteed package of settlement services. The proposed rule may impact the costs and pricing of HomeServices' mortgage, title and escrow services. The proposal was submitted to the Office of Management and Budget ("OMB") on December 16, 2003, and it is unknown whether the OMB will release the proposed rule; however, it is likely that the final rule could vary considerably from the initial proposal. Accordingly, the Company is presently unable to quantify the likely impact of the proposed rule, if adopted.

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 100% compliant 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 standards for ozone and fine particulate matter. Designations regarding attainment of the eight-hour ozone standard have recently been reviewed by the EPA, and the EPA has concluded that the entire state of Iowa is in attainment of the standards. On December 4, 2003, the EPA announced the development of its Interstate Air Quality Rule, a proposal to require coal-burning power plants in 29 states and the District of Columbia to reduce emissions of sulfur dioxide ("SO₂") and nitrogen oxides 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 for the regulation of mercury from coal-fired utilities as necessary to protect public health. 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 rule by December 2004. Any of these new or stricter standards could, in whole or in part, be superceded 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 regulations, MidAmerican Energy may be required to install control equipment on its generating stations or decrease the number of hours during which its generating stations operate. However, until final regulations are issued, the impact of the regulations on MidAmerican Energy cannot be predicted.

While legislative action is necessary for the Clear Skies Initiative or other multi-pollutant emission reduction legislation to become effective, MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions required to meet emissions reductions of this nature. On April 1, 2002, in accordance with an Iowa law passed in 2001, MidAmerican Energy filed with the IUB its first multi-year plan and budget for managing SO₂ and NO_X from its generating facilities in a cost-effective manner. The plan provides specific actions to be taken at each coal-fired generating facility and the related costs and timing for each action. Mercury emissions reductions were not addressed in the plan. On July 17, 2003, the IUB issued an order that affirmed an administrative law judge's approval of the plan, as amended. Accordingly, the IUB order provides that the approved expenditures will not be subject to a subsequent prudence review in a future electric rate case, but it rejected the future application of a tracker mechanism to recover emission reduction costs. However, pursuant to an unrelated rate settlement agreement approved by the IUB on October 17, 2003, if prior to January 1, 2011, capital and operating expenditures to comply with environmental requirements cumulatively exceed $325 million, then MidAmerican Energy may seek to recover the additional expenditures from customers. 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 (a "major modification") to an existing facility that potentially increases emissions, unless the changes are exempt under the regulations. 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 or 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 the present 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. After the NSR changes were announced, the EPA's enforcement branch indicated it would apply the clarified routine repair, maintenance and replacement rules to its pending investigation. A number of states and local air districts have challenged the EPA's clarification of the rule and a panel of the U.S. Circuit Court of Appeals for the District of Columbia issued an order on December 24, 2003 staying the EPA's implementation of its clarification of the equipment replacement rule.

On August 29, 2003, the EPA finalized requirements to reduce toxic air emissions from stationary combustion turbines. These requirements apply to turbines used at pipeline compressor stations that are built after January 12, 2003. Kern River and Northern Natural Gas believe the existing turbines are exempt from the rule since the turbines were built and installed at compressor stations built prior to January 12, 2003. New turbine installations will likely require the installation of equipment to reduce formaldehyde emissions and other pollutants to meet the new requirements and could significantly increase the cost of new turbine installations.

On December 19, 2002, the EPA issued proposed emission standards for hazardous air pollutants for stationary reciprocating internal combustion engines, such as those used at pipeline compressor stations. The proposed standards would apply to all new and certain existing reciprocating internal combustion engines above 500 horsepower that are located at facilities characterized under the Clean Air Act as a "major source" of toxic air pollutants. While the emission standards have not yet been finalized, the impact of any new regulation of hazardous air pollutants from stationary reciprocating internal combustion engines could have a significant impact on existing and new facilities.

Manufactured Gas Plants

The EPA and the state environmental agencies have determined that contaminated wastes remaining at decommissioned manufactured gas plant facilities may pose a threat to the public health or the environment if such contaminants are in sufficient quantities and at such concentrations as to warrant remedial action.

MidAmerican Energy has evaluated or is evaluating 27 properties that were, at one time, sites of gas manufacturing plants in which it may be a potentially responsible party. The purpose of these evaluations is to determine whether waste materials are present, whether the materials constitute a health or environmental risk, and whether MidAmerican Energy has any responsibility for remedial action. MidAmerican Energy is actively working with the regulatory agencies and has received regulatory closure on four sites. MidAmerican Energy is continuing to evaluate several of the sites to determine the future liability, if any, for conducting site investigations or other site activity.

MidAmerican Energy estimates the range of possible costs for investigation, remediation and monitoring for the sites discussed above to be approximately $11 million to $30 million. As of December 31, 2003, MidAmerican Energy has recorded a $14.0 million liability for these sites and a corresponding regulatory asset for future recovery through the regulatory process. MidAmerican Energy projects that these amounts will be incurred or paid over the next four years.

liabilities for these properties are based upon preliminary data. Thus, actual costs could vary significantly from the estimates. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action and changes in technology relating to remedial alternatives. Insurance recoveries have been received for some of the sites under investigation. Those recoveries are intended to be used principally for accelerated remediation, as specified by the IUB and are recorded as a regulatory liability.

Although the timing of potential incurred costs and recovery of such costs in rates may affect the results of operations in individual periods, management believes that the outcome of these issues will not have a material adverse effect on MidAmerican Energy's financial position, results of operations or cash flows.

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, 2003, CE Electric UK had 318 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 NED and YED. 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 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 MEHC 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.

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 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. 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. Quad Cities Station licenses currently expire in 2012. Exelon Generation submitted an application to renew the Quad Cities Station licenses with the NRC in January 2003. Action by the NRC on the application is expected by November 2004. Approval would result in the licenses allowing operation through 2032.

Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Exelon Generation, as required by the Nuclear Waste Act, signed a contract

with the Department of Energy to provide for the disposal of spent nuclear fuel and high-level radioactive waste beginning not later than January 1998. The Department of Energy did not begin receiving spent nuclear fuel on the scheduled date, and the schedule will be significantly delayed. The earliest expectation for completion is now 2010. The costs to be incurred by the Department of Energy for disposal activities are being financed by fees charged to owners and generators of the waste. Exelon Generation has informed MidAmerican Energy that existing on-site storage capability at Quad Cities Station is sufficient to permit interim storage into 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 expects the bulk of the construction work will be done in 2004 with 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.

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.

MidAmerican Energy has established external 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 2003 was $8.3 million.

Employees

As of December 31, 2003, the Company employed approximately 11,440 people, of which approximately 3,820 are represented by labor unions.

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. 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 Note 5 and Note 20 in "Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements" for additional information about the Company's properties.

MidAmerican Energy

MidAmerican Energy's most significant properties are its electric generation facilities. It is the opinion of management that the principal depreciable properties owned by MidAmerican Energy are in good operating condition and well maintained. For a discussion of these generation facilities, see "Item 1. Business — MidAmerican Energy." MidAmerican Energy'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.

The electric transmission system of MidAmerican Energy at December 31, 2003, included 918 miles of 345-kV lines and 1,128 miles of 161-kV lines. MidAmerican Energy's electric distribution system included approximately 220,400 transformers and 373 substations at December 31, 2003.

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, 2003, included 21,182 miles of gas mains and services pipelines.

Kern River and Northern Natural Gas

At December 31, 2003, Kern River's pipeline was comprised of two distinguishable sections: the mainline and the common facilities. The mainline section is comprised of the original 680 miles of 36-inch pipeline and 634.3 miles of 36-inch loop pipeline, and extends from the pipeline's point of origination in Opal, Wyoming through the Central Rocky Mountains area to Daggett, California and is owned entirely by Kern River. The common facilities consist of the 219-mile section of pipeline that extends from Daggett to Bakersfield, California. 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, 2003, Northern Natural Gas' system was comprised of approximately 7,300 miles of mainline transmission pipes and approximately 9,200 miles of smaller diameter branch lines and laterals. 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 liquefied natural gas 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, 2003, NED's and YED's electricity distribution networks (excluding service connection to consumers) on a combined basis included approximately 29,000 kilometers of overhead lines and approximately 63,000 kilometers of underground cables. In addition to the circuits referred to above, at December 31, 2003, NED's and YED's distribution facilities also included approximately 57,000 transformers and approximately 750 primary substations.

Other Properties

At December 31, 2003, MEHC's most significant physical properties, other than those owned by MidAmerican Energy, CE Electric UK, Kern River and Northern Natural Gas, 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" 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, 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. 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 on the fourth amended petition on August 22, 2003. 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 the 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 its tariff.

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. 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 the Company. 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 the Company. 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. Unless extended by agreement of the parties or by court order, MidAmerican Energy's answer and/or responsive pleading in this matter is due February 19, 2004. MidAmerican Energy will coordinate with the other defendants and vigorously defend the allegations against it.

Philippines

CE Casecnan NIA Arbitration

The CE Casecnan NIA arbitration was settled on October 15, 2003. See "Item 1. Business — CalEnergy Generation – Foreign" for additional information.

CE Casecnan Construction Contract Arbitration

The Casecnan project was constructed pursuant to a fixed-price, date-certain, turnkey construction contract by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa. (collectively, the "Contractor"), working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd.

In 2001, the Contractor filed a Request for Arbitration (and two supplements) with the International Chamber of Commerce ("ICC") seeking schedule relief of up to 153 days, compensation for alleged

additional costs of approximately $4 million (to the extent it is unable to recover from its insurer) and compensation for damages of approximately $62 million resulting from alleged force majeure events (and geologic conditions). The Contractor further alleged that the circumstances surrounding the placing of the Casecnan project into commercial operation in December 2001 amounted to a repudiation of the Replacement Contract resulting in a claim for unspecified quantum meruit damages, and that the delay liquidated damages clause which provides for payments of $125,000 per day to CE Casecnan for each day of delay in completion of the Casecnan project is unenforceable.

On November 7, 2002, the ICC issued the arbitration tribunal's partial award with respect to the Contractor's force majeure claims. The arbitration panel awarded the Contractor 18 days of schedule relief in the aggregate for all of the force majeure events and awarded the Contractor $3.8 million to the extent losses are not covered by insurance. All of the Contractor's other claims with respect to force majeure and geologic conditions were denied. If the Contractor were to prevail on the Contractor's claim that the delay liquidated damages clause is unenforceable, CE Casecnan would not be entitled to collect such delay damages for the period from March 31, 2001 through December 11, 2001. If the Contractor were to prevail in the Contractor's repudiation claim and prove quantum meruit damages in excess of amounts paid to the Contractor, CE Casecnan could be liable to make additional payments to the Contractor. CE Casecnan believes all of such allegations and claims are without merit and is vigorously contesting the Contractor's claims. CE Casecnan believes that an award will be issued by the ICC in 2004.

CE Casecnan Stockholder Litigation

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. In April 2002, CE Casecnan Ltd. and LPG entered into a status quo agreement pursuant to which CE Casecnan Ltd. agreed not to take any action to exercise control over or transfer LPG's shares in CE Casecnan. 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. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the stockholder agreement and alleged breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and MEHC to LPG. The complaint also seeks injunctive relief against all defendants and a declaratory judgment that LPG is entitled to maintain a 15% interest in CE Casecnan. On January 21, 2004, CE Casecnan Ltd. and LPG entered into a second status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and not distribute such funds without at least 15 days prior notice to LPG. Accordingly, 15% of the dividend distribution declared on January 21, 2004 was set aside by CE Casecnan in an unsecured CE Casecnan account. The impact, if any, of this litigation on the Company cannot be determined at this time.

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

Not applicable.

PART II


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

Since March 14, 2000, MEHC's equity securities have been owned by Berkshire Hathaway, Walter Scott, Jr. (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 consolidated financial data, which should be read in conjunction with the Company's financial statements and the related notes to those statements included in this annual report and with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" appearing elsewhere in this annual report. The selected consolidated financial data, as of and for the years ended December 31, 2003, 2002 and 2001, as of December 31, 2000 and for the periods from March 14, 2000 through December 31, 2000, have been derived from the Company's historical consolidated financial statements. The selected consolidated financial data, from January 1, 2000 through March 13, 2000 and as of and for the year ended December 31, 1999, have been derived from MEHC Predecessor's historical consolidated financial statements.

SELECTED CONSOLIDATED FINANCIAL DATA
(Amounts in millions)


	Year Ended December 31,							March 14, 2000 through December 31, 2000⁽³⁾		MEHC (Predecessor)
	Year Ended December 31,									January 1, 2000 through March 13, 2000⁽⁴⁾		Year Ended December 31, 1999⁽⁵⁾
	2003		2002⁽¹⁾		2001⁽²⁾					January 1, 2000 through March 13, 2000⁽⁴⁾		Year Ended December 31, 1999⁽⁵⁾
Statement of Operations Data:
Total revenue	$	6,144.7	$	4,968.1	$	4,973.0		$	4,013.0	$	1,075.8	$	4,368.5
Total costs and expenses		5,294.9		4,325.0		4,469.1			3,793.8		984.7		4,011.5
Income before change in accounting principle		415.6		380.0		147.3			81.3		51.3		167.2
Cumulative effect of change in accounting principle, net of tax		—		—		(4.6	)		—		—		—
Net income	$	415.6	$	380.0	$	142.7		$	81.3	$	51.3	$	167.2

Balance Sheet Data:
Total assets⁽⁶⁾	$	19,168.2	$	18,434.9	$	12,994.6		$	11,960.4		N/A	$	11,084.8
Parent company senior debt⁽⁷⁾		2,777.9		2,323.4		1,834.5			1,830.0		N/A		1,856.3
Parent company subordinated debt⁽⁷⁾		1,772.1		—		—			—		—		—
Company-obligated mandatory redeemable preferred securities of subsidiary trusts		—		2,063.4		788.2			786.5		N/A		450.0
Subsidiary and project debt⁽⁷⁾		6,674.6		7,077.1		4,754.8			3,398.7		N/A		3,642.7
Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts		—		—		100.0			100.0		N/A		101.6
Preferred securities of subsidiaries		92.1		93.3		121.2			145.7		N/A		146.6
Total stockholders' equity		2,771.4		2,294.3		1,708.2			1,576.4		N/A		994.6

(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 acquisition of MidAmerican Energy on March 12, 1999, MEHC's disposition of the Coso Joint Ventures on February 26, 1999, and MEHC's disposition of a 50% ownership interest in CE Generation on March 3, 1999 and includes $81.5 million of after tax income related to the settlement of political risk insurance proceeds related to MEHC's investment in Indonesia, gains on sales of shares of McLeodUSA, CE Electric UK restructuring charges and transaction costs related to MEHC's acquisition by a private investor group.

(6)

The Company originally filed its Annual Report on Form 10-K on February 9, 2004. In accordance with accounting guidance issued subsequent to that date, the Company has reclassified regulatory liabilities for the cost of removal of utility plant previously recognized within accumulated depreciation in the amounts of $385.7 million, $367.9 million, $349.5 million and $318.4 million, as of December 31, 2002, 2001, 2000 and 1999, respectively, as an other long-term accrued liability.

(7)	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 consolidated financial data and the consolidated financial statements included in Items 6 and 8 herein.

General

MEHC is a United States-based privately owned global energy company with publicly held fixed income securities that generates, distributes and supplies energy to utilities, government entities, retail customers and other customers located throughout the world. Through its subsidiaries, its 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), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and 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.

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 670,000 natural gas customers. Its natural gas pipeline subsidiaries operate interstate natural gas transmission systems with approximately 18,200 miles of pipeline in operation and peak delivery capacity of 6.2 Bcf of natural gas per day. The Company has interests in 6,716 net owned MW of power generation facilities in operation and construction, including 5,142 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.

During the past several years, the Company completed a number of significant transactions, including the following:


•	Northern Natural Gas was acquired in August 2002 for $882.7 million, net of cash acquired. Northern Natural Gas owns a 16,500 mile interstate natural gas pipeline extending from southwest Texas to the upper Midwest region of the United States with a design capacity of 4.4 Bcf of natural gas per day.


•	Kern River was acquired in March 2002 for $419.7 million, net of cash acquired. At the date of acquisition, Kern River owned 926 miles of interstate natural gas pipeline extending from Wyoming to markets in California, Nevada and Utah and with access to natural gas supplies from large producing regions in the Rocky Mountains and Canada.


•	In May 2003, Kern River completed a 717 mile expansion of its pipeline system, which increased the design capacity of the system by 885,626 Dth per day to 1,755,626 Dth per day.


•	HomeServices, MEHC's full-service independent residential real estate brokerage company, separately acquired seven real estate companies during 2003 and 2002.


•	CE Casecnan commenced operations on December 11, 2001.


•	On September 2001, CE Electric UK acquired 94.75% of Yorkshire from Innogy Holdings plc and simultaneously sold Northern Electric's electricity and gas supply and metering businesses to Innogy Holdings plc. In August 2002, CE Electric UK acquired the remaining 5.25% of Yorkshire from Xcel.

As a result of these events, the Company's future results may differ from historical results.

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

In 2003, net income available to common and preferred stockholders was $415.6 million compared with $380.0 million in 2002.

The increase was mainly due to: improved earnings at MidAmerican Energy, higher income at Kern River primarily due to the transportation fees earned in connection with the 2003 Expansion Project and, to a lesser degree, the inclusion of its operations for all of 2003, the acquisition of Northern Natural Gas in August 2002 and the inclusion of its operations for all of 2003, higher income at CE Electric UK due to lower costs and a weaker U.S. dollar and continued improvement at HomeServices due to acquisitions made throughout 2002 and 2003 and growth at existing companies which benefit from the low interest rate environment, a related increase in the mortgage refinance business and strong housing market. Offsetting those benefits were gains recorded, in 2002, of $41.3 million, after tax, from the sale of CE Gas assets and the tax benefits of $35.7 million in connection with the execution of the TPL restructuring agreement.

Operating revenue for the year ended December 31, 2003 increased $1,154.2 million or 24.1% to $5,948.2 million from $4,794.0 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			$ Change
Operating revenue:
MidAmerican Energy	$	2,600.2		$	2,240.9		$	359.3
Kern River		260.2			127.3			132.9
Northern Natural Gas		482.2			176.9			305.3
CE Electric UK		830.0			795.4			34.6
CalEnergy Generation – Domestic		45.8			38.5			7.3
CalEnergy Generation – Foreign		326.4			326.3			0.1
HomeServices		1,476.6			1,138.3			338.3
Segment operating revenue		6,021.4			4,843.6			1,177.8
Corporate/other		(73.2	)		(49.6	)		(23.6	)
Total operating revenue	$	5,948.2		$	4,794.0		$	1,154.2

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 MMBtu 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 off-system 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. The increase in Kern River's operating revenue 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 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 operating revenue increased during 2003 as 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, consisting mainly of commission revenue from real estate brokerage transactions, increased $247.0 million due to acquisitions made throughout 2002 and 2003 and $91.3 million due to growth at existing companies. During 2003, HomeServices closed 185,181 brokerage sides up 22.0% from 151,808 closed sides in 2002. Closed brokerage volume was $48.6 billion in 2003, up 31.7% from $36.9 billion in 2002.

Income on equity investments for the year ended December 31, 2003 decreased $2.3 million to $38.2 million from $40.5 million for the same period in 2002. 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 an independent power plant 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 from $8.8 million for the same period in 2002 primarily due to increased refinancing activity at mortgage joint ventures.

Interest and dividend income for the year ended December 31, 2003 decreased $8.4 million to $47.9 million from $56.3 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 following the redemption of the YED trust securities in June 2003 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 $32.9 million to $110.3 million from $77.4 million in 2002. Other income in 2003 resulted mainly from a $31.9 million gain recognized in connection with the NIA Arbitration settlement, equity AFUDC of $26.0 million, $13.8 million gain on sale of Williams' Cumulative Convertible Preferred Stock in June 2003 and $12.7 million of income at CE Electric UK mainly from the gain on sale of a local operational and dispatch facility at NED. Other income in 2002 resulted primarily from the gain on the sale of CE Gas assets of $54.3 million and equity AFUDC of $19.8 million. These items were offset, in 2002, by losses from the write-down of non-regulated investments at MidAmerican Energy of $21.9 million.

Cost of sales for the year ended December 31, 2003 increased $572.1 million, or 31.0%, to $2,416.1 million from $1,844.0 million for the same period in 2002.

MidAmerican Energy 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 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 expires 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 $178.8 million due to acquisitions made during 2002 and 2003. The remainder of HomeServices' increase was due to growth of existing companies totaling $56.8 million.

Operating expenses for the year ended December 31, 2003 increased $182.3 million, or 13.6%, to $1,527.5 million from $1,345.2 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 $30.7 million primarily due to the sale of the retail business in 2002, lower operating expenses of $24.3 million at CalEnergy Generation – Domestic primarily due to start-up costs at the Zinc facility in 2002, partially offset by increased overhaul costs at Cordova 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 $84.0 million, or 16.0%, to $609.9 million from $525.9 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.

Interest expense, less amounts capitalized, for the year ended December 31, 2003 increased $131.4 million to $741.3 million from $609.9 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 FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities" ("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 in the accompanying consolidated statements of operations. In addition, increases 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 YED securities, reductions in CalEnergy Generation – Foreign project debt, MEHC's revolving credit facility and the retirement of MEHC's 6.96% Senior Notes.

Provision for income tax for the year ended December 31, 2003 increased $151.4 million to $251.0 million from $99.6 million for the same period in 2002. The effective tax rate was 29.5% and 15.5% 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.

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. The increase in minority interest and preferred dividends is primarily due to the issuance of Company-obligated mandatorily redeemable preferred securities of subsidiary trusts relating to the Kern River and Northern Natural Gas acquisitions. This increase was partially offset by the adoption of FIN 46R described above and reduced dividends on subsidiary preferred securities resulting from lower outstanding balances.

Results of Operations for the Year Ended December 31, 2002 and the Year Ended December 31, 2001

In 2002, net income available to common and preferred stockholders was $380.0 million compared with $142.7 million in 2001.

The increase was mainly due to: acquisitions of Kern River in March 2002 and Northern Natural Gas in August 2002, increased income at CE Electric UK, primarily as a result of the gain on the sale of CE Gas assets, increased income at CalEnergy Generation – Foreign due to a full year of operations of the CE Casecnan project, improved earnings at MidAmerican Energy's regulated electric business and continued improvement at HomeServices due to acquisitions made throughout 2002 and growth at existing companies.

Operating revenue for the year ended December 31, 2002 increased $97.2 million or 2.1% to $4,794.0 million from $4,696.8 million for the same period in 2001.

The following table summarizes operating revenue by segment for the years ended December 31 (in millions):


	Year Ended December 31,
	2002			2001			$ Change
Operating revenue:
MidAmerican Energy	$	2,240.9		$	2,388.7		$	(147.8	)
Kern River		127.3			—			127.3
Northern Natural Gas		176.9			—			176.9
CE Electric UK		795.4			1,444.0			(648.6	)
CalEnergy Generation – Domestic		38.5			37.3			1.2
CalEnergy Generation – Foreign		326.3			203.5			122.8
HomeServices		1,138.3			641.9			496.4
Segment operating revenue		4,843.6			4,715.4			128.2
Corporate/other		(49.6	)		(18.6	)		(31.0	)
Total operating revenue	$	4,794.0		$	4,696.8		$	97.2

MidAmerican Energy regulated and non-regulated gas revenue decreased due to lower prices for gas purchased which is passed directly to the customer, partially offset by an increase in regulated electric retail sales for the year ended December 31, 2002 as compared to 2001 due primarily to higher relative temperatures in 2002, which occurred primarily in the third quarter of 2002.

Kern River and Northern Natural Gas were acquired in March 2002 and August 2002, respectively. The increases relate to their inclusion in MEHC's operations in 2002.

CE Electric UK operating revenue decreased primarily due to the sale of the supply business in 2001 partially offset by the acquisition of Yorkshire Electric in September 2001 and changes in the exchange rate. CE Electric UK distributed 41,157 GWh of electricity in the year ended December 31, 2002, compared with 23,770 GWh of electricity in the same period in 2001. The increase in electricity distributed is primarily due to the acquisition of Yorkshire distribution.

CalEnergy Generation – Foreign operating revenue for the year ended December 31, 2002 increased primarily due to commencement of commercial operation of the Casecnan project in December 2001.

HomeServices operating revenue for the year ended December 31, 2002 increased primarily due to contributions from 2002 acquisitions of $431.5 million. The remainder of HomeServices' increase was due to growth of existing companies of $105.3 million partially offset by a decrease of $40.4 million from a joint venture that was consolidated in 2001 and is accounted for under the equity method in 2002.

Interest and dividend income for the year ended December 31, 2002 increased $31.7 million or 128.9% to $56.3 million from $24.6 million for the same period in 2001. The increase was primarily due to increased interest income at CE Electric UK of $15.1 million due to the increased cash balance following the Yorkshire acquisition and increased corporate interest and dividends of $13.4 million primarily due to dividends received on the investment in Williams' Cumulative Preferred Stock.

Other income for the year ended December 31, 2002 decreased $134.7 million or 63.5% to $77.4 million from $212.1 million for the same period in 2001. Other income in 2002 resulted primarily from the non-recurring gain on the sale of CE Gas of $54.3 million and equity AFUDC of $19.8 million. These items were offset, in 2002, by losses from the write-down of non-regulated investments at MidAmerican Energy of $21.9 million. Other income in 2001 resulted from the non-recurring gains from the sales of Northern Electric's supply business, Telephone Flat and Western States Geothermal of $196.7 million, $20.7 million and $9.8 million, respectively, and a non-recurring gain from the transfer of Bali shares of $10.4 million. These items were partially offset, in 2001, by a charge related to the impairment of the Company's interest in TPL of $58.8 million.

Cost of sales for the year ended December 31, 2002 decreased $497.2 million or 21.2% to $1,844.0 million from $2,341.2 million for the same period in 2001.

MidAmerican Energy cost of sales for the year ended December 31, 2002 decreased $132.4 million or 11.8% to $988.9 million from $1,121.3 million for the same period in 2001, primarily due to decreases in regulated and non-regulated gas costs, caused by lower volumes and prices, partially offset by an increase in regulated electric costs caused by higher volumes, partially offset by the restructuring of the Cooper Nuclear Station contract.

CE Electric UK cost of sales for the year ended December 31, 2002 decreased $713.2 million or 84.6% to $129.5 million from $842.7 million for the same period in 2001. The decrease was primarily due to the sale of the supply business in 2001.

HomeServices cost of sales for the year ended December 31, 2002 increased $371.9 million or 94.0% to $767.6 million from $395.7 million for the same period in 2001. The increase was primarily due to costs at companies acquired during 2002 of $315.6 million, and higher commission expense resulting from increased sales at existing HomeServices businesses.

Operating expenses for the year ended December 31, 2002 increased $168.8 million or 14.3% to $1,345.2 million from $1,176.4 million for the same period in 2001. The increase was primarily due to higher costs at HomeServices of $99.1 million as a result of acquisitions, operating expenses due to the acquisitions of Northern Natural Gas of $95.0 million and Kern River of $27.2 million and plant operating expenses at the Zinc project and CE Casecnan of $33.9 million, partially offset by lower costs at MidAmerican Energy of $57.5 million primarily due to the restructuring of the Cooper Nuclear Station contract and lower energy efficiency expenses and lower costs at CE Electric UK of $28.5 million due to the sale of the supply business.

Depreciation and amortization for the year ended December 31, 2002 decreased $12.8 million or 2.4% to $525.9 million from $538.7 million for the same period in 2001. The decrease was primarily due to discontinuance of amortizing goodwill beginning January 1, 2002 of $96.4 million, partially offset by a full year of operations at CE Casecnan of $22.0 million, higher depreciation at MidAmerican Energy of $17.2 million primarily due to higher Iowa revenue sharing accruals and a change in the estimated useful lives of electric generation plant, depreciation expense due to the acquisitions of Kern River of $17.2 million and Northern Natural Gas of $18.2 million and increased amortization at HomeServices of $9.5 million primarily due to the amortization of the gross margin of pending sales contracts related to acquisitions.

Interest expense, less amounts capitalized, for the year ended December 31, 2002 increased $197.1 million or 47.7% to $609.9 million from $412.8 million for the same period in 2001. The increase was primarily due to the increase of interest expense at CE Electric UK of $71.3 million predominantly due to the debt acquired as part of the Yorkshire acquisition, interest expense due to debt related to the acquisitions of Kern River and Northern Natural Gas of $33.0 million and $23.0 million, respectively and the discontinuance of capitalizing interest related to the Casecnan project, the Cordova project and the Zinc Recovery project of $50.9 million, $9.4 million and $5.3 million, respectively, all partially offset by capitalized interest at Kern River of $14.0 million.

Tax expense for the year ended December 31, 2002 decreased $150.5 million or 60.2% to $99.6 million from $250.1 million for the same period in 2001. The effective tax rate was 15.5% and 49.6% for the years ended December 31, 2002 and 2001, respectively. The decrease is due primarily to the tax expense related

to the sale of the Northern Electric supply business in September 2001, the release of the tax obligation of $35.7 million in connection with the execution of the TPL restructuring agreement at CE Electric UK in 2002, and the recognition of a tax benefit in connection with the sale of the CE Gas assets in 2002.

Minority interest and preferred dividends for the year ended December 31, 2002 increased $57.0 million or 53.5% to $163.5 million from $106.5 million for the same period in 2001. Minority interest and preferred dividends includes the dividends on Company-obligated mandatorily redeemable preferred securities of subsidiary trusts. The increase in minority interest and preferred dividends is primarily due to the issuance of Company-obligated mandatorily redeemable preferred securities of subsidiary trusts relating to the Kern River and Northern Natural Gas acquisitions.

Effective January 1, 2001, the Company changed its accounting policy regarding major maintenance and repairs for non-regulated gas projects, non-regulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of monthly accruals based on long-term scheduled maintenance plans for the gas projects and deferral and amortization of plant overhaul costs and geothermal well rework costs over the estimated useful lives. The cumulative effect of the change in accounting principle for 2001 was $4.6 million, net of taxes.

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 debt 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.

The Company's cash and cash equivalents were $660.2 million at December 31, 2003, compared to $844.4 million at December 31, 2002. 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.

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 $119.5 million and $58.7 million at December 31, 2003, and December 31, 2002, 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 and customer deposits held in escrow.

Cash flows from Operating Activities

The Company generated cash flows from operations of $1,217.9 million for the year ended December 31, 2003, compared with $757.7 million for the same period in 2002. The increase was mainly due to the positive impacts of the Kern River, Northern Natural Gas and HomeServices' acquisitions as well as accelerated tax depreciation benefits.

Cash Flows from Investing Activities

Cash flows used in investing activities for 2003 were $1,003.2 million, of which $1,191.0 million was used for capital expenditures, construction and other development costs. Cash flows used in investing activities for 2002 were $2,907.8 million, of which $1,508.1 million was used for capital expenditures, construction and other development costs. Investing activities in 2002 includes $1,416.9 million for acquisitions.

Capital Expenditures, Construction and Other Development Costs

Capital expenditures, construction and other development costs by business segment for 2003 and 2002 are as follows (in millions):


	Year Ended December 31,
	2003		2002
MidAmerican Energy	$	378.5	$	358.2
Kern River		361.5		769.5
Northern Natural Gas		104.4		62.4
CE Electric UK		301.9		222.6
CalEnergy Generation – Domestic		17.9		61.9
CalEnergy Generation – Foreign		8.5		7.8
HomeServices		18.3		18.3
Segment capital expenditures		1,191.0		1,500.7
Corporate/other		0.1		7.4
Total capital expenditures	$	1,191.1	$	1,508.1

Capital expenditures and construction and other development costs for 2004 are expected to be approximately $1.3 billion.

MidAmerican Energy Capital Expenditures, Construction and Development Costs

MidAmerican Energy's primary need for capital is utility construction expenditures. For 2003, utility construction expenditures totaled $376.2 million, including allowance for funds used during construction and Quad Cities Station nuclear fuel purchases.

Forecasted utility construction expenditures, including allowance for funds used during construction, are $844 million for 2004. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. MidAmerican Energy expects to meet these capital expenditures with cash flows from operations and the issuance of long-term debt.

In order to address projected capacity needs for its regulated customers, MidAmerican Energy is currently constructing two electric generating projects in Iowa and developing a third. Upon completion, the projects will provide service to regulated retail electricity customers. MidAmerican Energy has obtained regulatory approval to include the actual costs of the generation projects in its Iowa rate base as long as actual costs do not exceed an agreed upon cap that MidAmerican Energy has deemed to be reasonable. Wholesale sales may also be made from the projects to the extent the power is not needed for regulated retail service. MidAmerican Energy expects to invest approximately $1.4 billion in the three projects, of which approximately $314 million has been invested through December 31, 2003.

The first project is a natural gas-fired combined cycle unit with an estimated cost of $357 million, excluding allowance for funds used during construction. MidAmerican Energy will own and operate the plant. Commercial operation of the simple cycle mode began on May 5, 2003. The plant, which will continue to be operated in simple cycle mode during 2004, resulted in 327 MW of accredited capacity in the summer of 2003. The combined cycle operation is expected to commence in December 2004 and achieve an expected additional accredited capacity of 190 MW.

The second project is currently under construction and is 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 to be approximately $713 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 May 29, 2003, the IUB issued an order that approves the ratemaking principles for the plant, and on June 27, 2003, MidAmerican Energy received a certificate from the IUB allowing MidAmerican Energy to construct the

plant. On February 12, 2003, MidAmerican Energy executed a contract with 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. MidAmerican Energy is also seeking an order from the IUB approving construction of the associated transmission facilities.

The third project is currently under development and is comprised of wind power facilities totaling 310 MW based on the nameplate rating. Generally speaking, accredited capacity ratings for the 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. If constructed, MidAmerican Energy will own and operate these facilities, which are expected to cost approximately $323 million. MidAmerican Energy's plan to construct the wind project is in conjunction with a settlement agreement that extends through December 31, 2010, an Iowa retail electric rate freeze that was previously scheduled to expire at the end of 2005. The settlement agreement, which was filed with the IUB as part of MidAmerican Energy's application for ratemaking principles for the wind project, was approved by the IUB on October 17, 2003. The obligation of MidAmerican Energy to construct the wind project may be terminated by MidAmerican Energy if the federal production tax credit applicable to the wind energy facilities is not available at a rate of 1.8 cents per kWh for a period of at least ten years after the facilities begin generating electricity. The production tax credit is available only to wind facilities placed in service before January 1, 2004. MidAmerican Energy has also received authorization from the IUB to construct the wind power project. If MidAmerican Energy does not construct the wind facilities by December 31, 2007, the rate extension from January 1, 2006 through December 31, 2010 may terminate.

Kern River's 2003 Expansion Project

On May 1, 2003, Kern River completed the construction of its 2003 Expansion Project at a total cost of approximately $1.2 billion. The expansion increased the design capacity of the existing Kern River pipeline by 885,626 Dth per day to 1,755,626 Dth per day.

Also on May 1, 2003, Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the approximately $815 million of outstanding borrowings under Kern River's $875 million credit facility. Kern River entered into this credit facility in 2002 to finance the construction of the 2003 Expansion Project. The credit facility and a completion guarantee issued by MEHC in favor of the lenders was terminated.

Other Development Costs

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 IID pursuant to a power purchase agreement. TransAlta is currently funding 50% of the development costs of this project. On December 17, 2003, the CEC issued final approval for construction of the facility. If the project is constructed, MEHC expects capital expenditures to total approximately $550.0 million and currently plans to fund its interest in this project with available cash and future issuances of debt.

Acquisitions

Kern River

In March 2002, MEHC acquired Kern River for $419.7 million, net of cash acquired and a working capital adjustment. At the time, Kern River owned a 926-mile interstate natural gas pipeline extending from Wyoming to markets in California, Nevada and Utah and accesses natural gas supplies from large producing regions in the Rocky Mountains and Canada. MEHC used the proceeds from the issuances of $323.0 million of 11% Company-obligated mandatorily redeemable preferred securities of 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 to finance the acquisition.

Northern Natural Gas

In August 2002, MEHC acquired Northern Natural Gas for $882.7 million, net of cash acquired and a working capital adjustment. Northern Natural Gas owns a 16,500-mile interstate natural gas pipeline

extending from southwest Texas to the upper Midwest region of the United States with a design capacity of 4.4 Bcf of natural gas per day. Northern Natural Gas also operates three natural gas storage facilities and two liquefied natural gas peaking units with a total storage capacity of 59 Bcf and peak delivery capability of over 1.3 Bcf of natural gas per day. Northern Natural Gas accesses natural gas supply from many of the larger producing regions in North America, including the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian basins. The pipeline system provides transportation and storage services to utilities, municipalities, other pipeline companies, gas marketers and industrial and commercial users. MEHC used the proceeds from a $950.0 million investment in its subsidiary trust's preferred securities by Berkshire Hathaway to finance the acquisition.

HomeServices' Acquisitions

In 2003, HomeServices separately acquired four real estate companies for an aggregate purchase price of approximately $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 approximately $102.9 million on 16,000 closed sides representing $3.6 billion of sales volume. Additionally, HomeServices is obligated to pay a maximum earnout of $5.2 million based on 2004 and 2005 financial performance measures. These purchases were financed using HomeServices' internally generated cash flows and revolving credit facility. In 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of approximately $106.1 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2001, these real estate companies had combined revenue of approximately $356.0 million on 42,000 closed sides representing $13.7 billion of sales volume. Additionally, HomeServices was obligated to pay an earnout of $17.3 million based on 2002 financial performance measures. These purchases were financed using HomeServices' internally generated cash flows, revolving credit facility and $40.0 million from MEHC, which was contributed to HomeServices as equity.

Williams' Cumulative Convertible Preferred Stock

On June 10, 2003, Williams repurchased, for approximately $288.8 million, plus accrued dividends, all of the shares of its 9-7/8% Cumulative Convertible Preferred Stock originally acquired by the Company in March 2002 for $275.0 million.

Put of ROP Bond and Receipt of Cash

Cash Flows from Financing Activities

Cash flows used in financing activities for 2003 were $426.3 million. During 2003, the Company used cash for financing activities, totaling $1,937.9 million, for repayments of parent and subsidiary long-term obligations, and generated cash from financing activities, totaling $1,606.9 million, from the issuance of subsidiary, project and parent company senior debt. Cash flows from financing activities for 2002 were $2,555.2 million. During 2002, the Company generated cash from financing activities, totaling $3,860.3 million, from the issuance of trust preferred securities, common and preferred stock and subsidiary, project and parent company debt, and used cash for financing activities, totaling $1,243.9 million, for repayments of parent and subsidiary long-term obligations.

Recent Debt Issuances and Redemptions

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.

On February 10, 2003, MidAmerican Energy redeemed all $75.0 million of its 7.375% series of mortgage bonds, and on March 17, 2003, it redeemed all $6.94 million of its 7.45% series of mortgage bonds. Additionally, MidAmerican Energy's 7.125% series of mortgage bonds totaling $100 million matured on February 3, 2003. On October 17, 2003, MidAmerican Energy redeemed all $12.5 million of its 6.95% series of mortgage bonds at 103.48% of the principal amount.

On May 16, 2003, MEHC issued $450 million of its 3.5% Senior Notes which mature on May 15, 2008. The proceeds were used for general corporate purposes.

In the second quarter of 2003, MEHC terminated its $400 million credit facility. On June 6, 2003, MEHC closed on a new $100 million revolving credit facility which expires on June 6, 2006. The facility supports letters of credit of which $73.0 million were outstanding at December 31, 2003.

On June 9, 2003, Yorkshire Power Group Limited, a wholly owned indirect subsidiary of CE Electric UK, completed the redemption in full of the outstanding shares of the Yorkshire Capital Trust I, 8.08% trust securities, due June 30, 2038, and paid $243.4 million in principal amount ($25 liquidation amount per each trust security) plus accrued distributions of $0.381555555 per trust security to the redemption date. The redemption price was paid to holders of the trust security on the redemption date.

On September 15, 2003, MEHC repaid its $215.0 million, 6.96% Senior Notes.

During 2003, MEHC purchased approximately $88.3 million of original face amount of debt obligations of its subsidiaries of which $37.5 million is held in other investments with the remainder being retired.

During 2003, CE Electric UK and its subsidiaries purchased and retired approximately $50 million of outstanding indebtedness.

On January 30, 2004, Salton Sea Funding Corporation ("SSFC"), a wholly owned subsidiary of CE Generation, announced its election to redeem an aggregate principal amount of approximately $136.4 million of its 7.475% Senior Secured Series F Bonds due November 30, 2018, pro rata, at a redemption price of 100% of such aggregate outstanding principal amount, plus accrued interest to the date of redemption. The trustee delivered a redemption notice to the holders of the bonds on January 29, 2004. The record date for the redemption is February 15, 2004 and the redemption is expected to be completed on March 1, 2004. SSFC expects to make a demand on MEHC for the full amount remaining on MEHC's guarantee of the Series F Bonds in order to fund the redemption. Upon the expected demand and payment under MEHC's guarantee, MEHC will no longer have any liability with respect to its guarantee.

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. 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, 2003, MidAmerican Energy's estimated potential collateral requirements totaled approximately $89 million. MidAmerican Energy's collateral requirements could fluctuate considerably due to seasonality, market price volatility, a loss of key MidAmerican Energy generating facilities or other related factors.

Yorkshire Power Group Limited, 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, 2003, 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, 2003 is approximately $62.6 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 Yorkshire Power Group Limited's credit ratings from the three recognized credit rating agencies decline below investment grade. As of December 31, 2003, Yorkshire Power Group Limited'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 $29.0 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, 2003 are as follows (in millions):


	Payments Due By Period
	Total		< 1 Year		2-3 Years		4-5 Years		> 5 Years
Contractual Cash Obligations:
Parent company senior debt	$	2,777.9	$	—	$	260.0	$	1,550.0	$	967.9
Parent company subordinated debt		1,872.1		100.0		422.6		468.0		881.5
Subsidiary and project debt ⁽¹⁾		7,175.6		500.9		864.5		917.6		4,892.6
Preferred securities of subsidiaries		92.1		—		—		—		92.1
Coal, electricity and natural gas contract commitments ⁽²⁾		593.1		179.0		204.5		101.2		108.4
Operating leases ⁽²⁾		290.1		53.1		87.9		64.1		85.0
Total contractual cash obligations	$	12,800.9	$	833.0	$	1,839.5	$	3,100.9	$	7,027.5


	Commitment Expiration per Period
	Total		< 1 Year		2-3 Years		4-5 Years		> 5 Years
Other Commercial Commitments:
Unused parent company revolving lines of credit	$	26.4	$	—	$	26.4	$	—	$	—
Parent company letters of credit		73.6		73.0		0.6		—		—
Unused subsidiary lines of credit		138.0		13.0		125.0		—		—
Total other commercial commitments	$	238.0	$	86.0	$	152.0	$	—	$	—

(1)	Total less than one year includes $136.4 million expected to be redeemed on March 1, 2004.

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

Off-Balance Sheet Arrangements

The Company has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on the Company's balance sheet as an equity investment and is increased or decreased for the the Company's pro-rata share of earnings or losses, respectively, less any dividend distribution from such investments.

As of December 31, 2003, the Company's investments which are accounted for under the equity method had $924.6 million of debt and $39.5 million in outstanding letters of credit. As of December 31,

2003, the Company's pro-rata share of such debt, which is non-recourse to MEHC, was $394.1 million. The $394.1 million excludes the $136.4 million of debt which MEHC has guaranteed on the Salton Sea Funding Series F Bonds and which is included in the the Company's consolidated balance sheet at December 31, 2003. This amount is expected to be redeemed on March 1, 2004. As of December 31, 2003, the Company's pro-rata share of its equity investments' outstanding letters of credit was $16.7 million and was non-recourse to MEHC.

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

On January 1, 2003, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations". This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. The cumulative effect of initially applying this statement by the Company was immaterial.

The Company identified legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. On January 1, 2003, the Company recorded $289.3 million of asset retirement obligation ("ARO") liabilities; $13.9 million of ARO assets, net of accumulated depreciation; $114.6 million of regulatory assets; and reclassified $1.0 million of accumulated depreciation to the ARO liability. The initial ARO liability recognized includes $266.5 million that pertains to obligations associated with the decommissioning of the Quad Cities nuclear station. The $266.5 million includes a $159.8 million nuclear decommissioning liability that had been recorded at December 31, 2002. The adoption of this statement did not have a material impact on the operations of the regulated entities, as the effects were offset by the establishment of regulatory assets, totaling $114.6 million, pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation".

On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" ("SFAS 149"). SFAS 149 amends SFAS No. 133 for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. SFAS 149 requires contracts with comparable characteristics to be accounted for similarly. In particular, SFAS 149 clarifies when a contract with an initial net investment meets the characteristic of a derivative and clarifies when a derivative that contains a financing component will require special reporting in the statement of cash flows. SFAS 149 is effective for the Company for contracts entered into or modified after June 30, 2003. The adoption of SFAS 149 did not have a material effect on the Company's financial position, results of operations or cash flows.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("SFAS 150"). SFAS 150 established standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). The standard is effective for the Company for fiscal periods beginning after December 15, 2003. The adoption of SFAS 150 is not expected to have a material effect on the Company's financial position, results of operations or cash flows.

In December 2003, the FASB issued FIN 46R, which served to clarify guidance in Financial Interpretation No. 46 ("FIN 46"), and provided additional guidance surrounding the application of FIN 46. The Company adopted and applied the provisions of FIN 46R 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, of approximately $1.9 billion, being reclassified to parent company subordinated debt in the accompanying consolidated balance sheet as of December 31, 2003. In addition, the associated amounts previously recorded as minority interest are now recorded as interest expense in the accompanying consolidated statement of operations. For the period from October 1, 2003 to December 31, 2003, the Company has recorded $49.8 million of interest expense related to these securities. In accordance with the requirements of FIN 46R, no amounts prior to adoption on October 1, 2003 have been reclassified. The Company will adopt the provisions of FIN 46R related to non-special purpose entities in the first quarter of 2004, in accordance with the

provisions of FIN 46R. The Company is currently evaluating the impact of FIN 46R on several operating joint ventures that the Company currently does not consolidate.

Critical Accounting Policies

The preparation of financial statements and related documents in conformity with generally accepted accounting principles in the United States of America ("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, 2003 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 Statement of Financial Accounting Standards ("SFAS") No. 71 ("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 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

The Company's long-lived assets consist primarily of properties, plants and equipment and acquired goodwill. 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's 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 Company also evaluates goodwill for impairment annually, primarily using a discounted cash flow methodology.

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 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.

On January 1, 2002, the Company adopted 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, but will be tested for impairment on an annual basis. The Company's related amortization consists solely of goodwill amortization. In accordance with SFAS 142, the Company completed its annual goodwill impairment test, as of October 31, 2003, primarily using a discounted cash flow methodology. No impairment was indicated as a result of the impairment tests.

Contingent Liabilities

The Company establishes reserves for estimated loss contingencies, such as environmental, legal and income taxes, 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 reflected in operations 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. Reserves 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 any matters. Should the outcomes differ from the assumptions and estimates, revisions to the estimated reserves 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.

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. The unbilled revenue estimate is reversed in the following month.

Where there is an over recovery 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 are 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 cases. Kern River and Northern Natural Gas record rate refund liabilities considering their regulatory proceedings and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.

Revenue from water 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, 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 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 $387.3 million if interest rates were to increase by 10% from their levels at December 31, 2003. 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, 2002, the Company had fixed-rate long-term debt and Company-obligated mandatorily redeemable preferred securities of subsidiary trusts of $11,683.2 million in aggregate principal amount and having a fair value of $12,188.8 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, 2003, the Company had floating-rate obligations of $459.8 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, 2003 principal balances.

At December 31, 2002, the Company had floating-rate obligations of $425.1 million that expose 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 certain currency rate swap agreements for its Senior Notes with two 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 $117.1 million of 6.853% Senior Notes, the agreements extend until maturity on December 30, 2004 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.744%. For the $236.2 million of 6.995% Senior Notes, 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, 2003 is approximately $16.0 million 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.

Yorkshire 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 6.496% Yankee Bonds, 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, 2003 is approximately $62.6 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.

A decrease of 10% in the December 31, 2003 rate of exchange of Sterling to dollars would increase the amount owed by the Company if these swap agreements were terminated by approximately $97.4 million.

Derivatives

MidAmerican Energy enters into various financial derivative instruments, including futures, over-the-counter swaps and forward physical contracts. Senior management provides the overall direction, structure, conduct and control of MidAmerican Energy's risk management activities, including authorization and communication of risk management policies and procedures, the use of financial derivative instruments, 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.

As of December 31, 2003, MidAmerican Energy held derivative instruments used for non-trading and trading purposes with the following fair values (in thousands):


Contract Type	Maturity in 2004			Maturity in 2005-07			Total
Non-trading:
Regulated electric assets	$	5,924		$	217		$	6,141
Regulated electric (liabilities)		(14,275	)		—			(14,275	)
Regulated gas assets		9,008			—			9,008
Regulated weather (liabilities)		(1,775	)		—			(1,775	)
Nonregulated electric assets		2,953			1,676			4,629
Nonregulated electric (liabilities)		(1,711	)		(1,131	)		(2,842	)
Nonregulated gas assets		11,498			798			12,296
Nonregulated gas (liabilities)		(11,867	)		(739	)		(12,606	)
Total		(245	)		821			576

Trading:
Nonregulated gas assets		389			247			636
Nonregulated gas (liabilities)		(419	)		—			(419	)
Total		(30	)		247			217

Total MidAmerican Energy assets	$	29,772		$	2,938		$	32,710
Total MidAmerican Energy (liabilities)	$	(30,047	)	$	(1,870	)	$	(31,917	)

Item 8. Financial Statements and Supplementary Data.


Independent Auditors' Report					57
Consolidated Balance Sheets as of December 31, 2003 and 2002					58
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001					59
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2003, 2002 and 2001					60
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001					61
Notes to Consolidated Financial Statements					62

INDEPENDENT AUDITORS' REPORT

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, 2003 and 2002, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2003. 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 auditing standards generally accepted in the United States of America. 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 examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, 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 Note 2 to the consolidated financial statements, the Company changed its accounting policy for asset retirement obligations and for variable interest entities in 2003, for goodwill and other intangible assets in 2002, and for major maintenance, overhaul and well workover costs in 2001.

/s/ Deloitte & Touche LLP

DELOITTE & TOUCHE LLP
Des Moines, Iowa
February 9, 2004
(March 1, 2004 as to Notes 2, 5 and 20)

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands)


	As of December 31,
	2003			2002
ASSETS
Current assets:
Cash and cash equivalents	$	660,213		$	844,430
Restricted cash and short-term investments		55,281			50,808
Accounts receivable, net of allowance for doubtful accounts of $26,004 and $39,742		666,063			707,731
Inventories		123,301			126,938
Other current assets		371,855			246,731
Total current assets		1,876,713			1,976,638
Properties, plants and equipment, net		11,180,979			10,284,487
Goodwill		4,305,643			4,258,132
Regulatory assets		512,549			415,804
Other investments		228,896			446,732
Equity investments		234,370			273,707
Deferred charges and other assets		829,039			779,420
Total assets	$	19,168,189		$	18,434,920
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	345,237		$	462,960
Accrued interest		189,635			192,015
Accrued taxes		112,823			108,940
Other accrued liabilities		443,531			457,058
Short-term debt		48,036			79,782
Current portion of long-term debt		500,941			470,213
Current portion of parent company subordinated debt		100,000			—
Total current liabilities		1,740,203			1,770,968
Other long-term accrued liabilities		1,827,633			1,486,608
Parent company senior debt		2,777,878			2,323,387
Parent company subordinated debt		1,772,146			—
Subsidiary and project debt		6,674,640			7,077,087
Deferred income taxes		1,433,144			1,238,421
Total liabilities		16,225,644			13,896,471
Deferred income		69,201			80,078
Minority interest		9,754			7,351
Preferred securities of subsidiaries		92,145			93,325
Company-obligated mandatorily redeemable preferred securities of subsidiary trusts		—			2,063,412
Commitments and contingencies (Note 19)
Stockholders' equity:
Zero coupon convertible preferred stock — authorized 50,000 shares, no par value; 41,263 shares outstanding at December 31, 2003 and 2002		—			—
Common stock — authorized 60,000 shares, no par value; 9,281 shares issued and outstanding at December 31, 2003 and 2002		—			—
Additional paid-in capital		1,957,277			1,956,509
Retained earnings		999,627			584,009
Accumulated other comprehensive loss, net		(185,459	)		(246,235	)
Total stockholders' equity		2,771,445			2,294,283
Total liabilities and stockholders' equity	$	19,168,189		$	18,434,920

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,
	2003			2002			2001
Revenue:
Operating revenue	$	5,948,224		$	4,794,010		$	4,696,781
Income on equity investments		38,224			40,520			39,565
Interest and dividend income		47,911			56,250			24,552
Other income		110,318			77,359			212,082
Total revenue		6,144,677			4,968,139			4,972,980
Costs and expenses:
Cost of sales		2,416,132			1,844,024			2,341,178
Operating expense		1,527,516			1,345,205			1,176,422
Depreciation and amortization		609,889			525,902			538,702
Interest expense		771,831			647,379			499,263
Less interest capitalized		(30,483	)		(37,469	)		(86,469	)
Total costs and expenses		5,294,885			4,325,041			4,469,096
Income before provision for income taxes		849,792			643,098			503,884
Provision for income taxes		250,971			99,588			250,064
Income before minority interest and preferred dividends		598,821			543,510			253,820
Minority interest and preferred dividends		183,203			163,467			106,547
Income before cumulative effect of change in accounting principle		415,618			380,043			147,273
Cumulative effect of change in accounting principle, net of tax (Note 2)		—			—			(4,604	)
Net income available to common and preferred stockholders	$	415,618		$	380,043		$	142,669

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

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Amounts in thousands)


	Outstanding Common Shares		Common Stock		Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, January 1, 2001		9,281	$	—	$	1,553,073	$	81,257		$	(57,929	)	$	1,576,401
Net income		—		—		—		142,669			—			142,669
Other comprehensive income: Foreign currency translation adjustment		—		—		—		—			(22,103	)		(22,103	)
Fair value adjustment on cash flow hedges, net of tax of $8,143		—		—		—		—			18,490			18,490
Minimum pension liability adjustment, net of tax of $(3,448)		—		—		—		—			(4,847	)		(4,847	)
Unrealized losses on securities, net of tax of $(1,315)		—		—		—		—			(2,443	)		(2,443	)
Total other comprehensive income														131,766
Balance, December 31, 2001		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 other 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 losses on securities, net of tax of $566		—		—		—		—			848			848
Total other 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

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,
	2003			2002			2001
Cash flows from operating activities:
Net income	$	415,618		$	380,043		$	142,669
Adjustments to reconcile net cash flows from operating activities:
Distributions less income on equity investments		40,160			(11,383	)		(28,515	)
Gains on asset sales		(24,321	)		(25,329	)		(179,493	)
Depreciation and amortization		609,889			525,902			442,284
Amortization of goodwill		—			—			96,418
Amortization of regulatory assets and liabilities and other		(14,363	)		8,709			23,774
Amortization of deferred financing costs		28,046			28,615			20,737
Provision for deferred income taxes		237,322			(16,228	)		152,920
Cumulative effect of change in accounting principle, net of tax		—			—			4,604
Changes in other items:
Accounts receivable and other current assets		(27,447	)		(201,147	)		571,910
Accounts payable and other accrued liabilities		(46,138	)		64,759			(420,434	)
Deferred income		(9,344	)		(4,839	)		6,428
Other		8,501			8,624			13,696
Net cash flows from operating activities		1,217,923			757,726			846,998
Cash flows from investing activities:
Acquisitions, net of cash acquired		(54,263	)		(1,416,937	)		(81,934	)
Sale (purchase) of convertible preferred securities		288,750			(275,000	)		—
Capital expenditures relating to operating projects		(677,256	)		(542,615	)		(398,165	)
Construction and other development costs		(513,771	)		(965,470	)		(178,587	)
Purchase of affiliates notes		(35,029	)		—			(13,247	)
Proceeds from sale of assets		13,113			214,070			377,396
Decrease in restricted cash and investments		7,415			16,351			24,540
Other		(32,126	)		61,790			31,453
Net cash flows from investing activities		(1,003,167	)		(2,907,811	)		(238,544	)
Cash flows from financing activities:
Proceeds from subsidiary and project debt		1,157,649			1,485,349			200,000
Proceeds from parent company senior debt		449,295			700,000			—
Repayments of subsidiary and project debt		(1,490,986	)		(395,370	)		(437,372	)
Repayment of parent company senior debt		(215,000	)		—			—
Repayment of parent company subordinated debt		(198,958	)		—			—
Net proceeds from (repayment of) parent company revolving credit facility		—			(153,500	)		68,500
Repayment of other obligations		—			(94,297	)		—
Net repayment of subsidiary short-term debt		(31,750	)		(472,835	)		(74,144	)
Proceeds from issuance of trust preferred securities		—			1,273,000			—
Proceeds from issuance of preferred stock		—			402,000			—
Redemption of preferred securities of subsidiaries		(1,176	)		(127,908	)		(24,910	)
Other		(95,411	)		(61,205	)		9,459
Net cash flows from financing activities		(426,337	)		2,555,234			(258,467	)
Effect of exchange rate changes		27,364			52,536			(1,394	)
Net change in cash and cash equivalents		(184,217	)		457,685			348,593
Cash and cash equivalents at beginning of period		844,430			386,745			38,152
Cash and cash equivalents at end of period	$	660,213		$	844,430		$	386,745
Supplemental Disclosure:
Interest paid, net of interest capitalized	$	706,039		$	588,972		$	389,953
Income taxes paid	$	9,911		$	101,225		$	133,139
Non-cash transaction – ROP note received under NIA Arbitration Settlement	$	97,000		$	—		$	—

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") is a United States-based privately owned global energy company. The Company's operations 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 plc ("Northern Electric ") and Yorkshire Electricity Group plc ("Yorkshire ")), CalEnergy Generation-Domestic (interests in independent power projects and related operations), CalEnergy Generation-Foreign (the subsidiaries owning the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively the "Leyte Projects") and the Casecnan project) 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 was 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, MMBtus means million British thermal units and Dth means decatherms or MMBtus.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of MEHC and its wholly owned subsidiaries excluding entities for which adoption of FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities" ("FIN 46R") was required at December 31, 2003. 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 accumulated other comprehensive income (loss) 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 2002 and 2001 consolidated financial statements and supporting note disclosures have been reclassified to conform to the fiscal 2003 presentation. Such reclassification did not impact previously reported net income or retained earnings.

The Company originally issued its 2003 consolidated financial statements on February 9, 2004. In accordance with accounting guidance issued subsequent to that date, the Company has adjusted the consolidated financial statements to reflect the reclassification of $385.7 million of 2002 regulatory liabilities and $367.9 million of 2001 regulatory liabilities for the cost of removal of utility plant previously recognized within accumulated depreciation as an other long-term accrued liability. Prior to this reclassification, 2002 properties, plants and equipment, net was $9.9 billion, total assets were $18.0 billion, other long-term accrued liabilities were $1.1 billion and total liabilities were $13.5 billion. Subsequent to this reclassification, 2002 properties, plants and equipment, net is $10.3 billion, total assets are $18.4 billion, other long-term accrued liabilities are $1.5 billion, and total liabilities are $13.9 billion.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States 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

Cash and Cash Equivalents

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.

Restricted Cash and Investments

The current restricted cash and short-term investments balance recorded separately in restricted cash and short term investments and in deferred charges and other assets, was $119.5 million and $58.7 million at December 31, 2003 and 2002, 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 and customer deposits held in escrow. 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.

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. The Company is unable to estimate a fair value for the Leyte debt as there are no quoted market prices available.

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.

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

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.

Goodwill

On January 1, 2002, the Company adopted 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, but will be tested for impairment on an annual basis. The Company's related amortization consisted primarily of goodwill amortization. Following is a reconciliation of net income available to common and preferred stockholders as originally reported for the years ended December 31, 2003, 2002 and 2001 to adjusted net income available to common and preferred stockholders (in thousands):


	Year Ended December
	2003		2002		2001
Reported net income available to common and preferred stockholders	$	415,618	$	380,043	$	142,669
Amortization of goodwill		—		—		96,418
Tax effect of amortization		—		—		(2,018	)
Adjusted net income available to common and preferred stockholders	$	415,618	$	380,043	$	237,069

The Company completed its annual review pursuant to SFAS 142 for its reporting units during the fourth quarter of 2003 primarily using a discounted cash flow methodology. No impairment was indicated as a result of these assessments.

Capitalization of Interest and 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 utility plant 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

Deferred 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. The Company does not intend to repatriate earnings of foreign subsidiaries in the foreseeable future. As a result, deferred United States income taxes are not provided for currency translation adjustments, retained earnings of international subsidiaries or corporate joint ventures unless the earnings are intended to be remitted.

Revenue Recognition

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 accrued liabilities. Where there is an under recovery, no anticipation of any potential future recovery is made.

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 cases. Kern River and Northern Natural Gas record rate refund liabilities, which are included in other accrued liabilities, considering their regulatory proceedings and other third party regulatory proceedings, advice of counsel and estimated total exposure, as well as collection and other risks.

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.

Accounting Principle Change

Effective January 1, 2001, the Company changed its accounting policy regarding major maintenance and repairs for non-regulated gas projects, non-regulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of accruals based on long-term scheduled maintenance plans for the gas projects and deferral and amortization of plant overhaul costs and geothermal well rework costs over the estimated useful lives. The cumulative effect of the change in accounting principle was $4.6 million, net of taxes of $0.7 million.

New Accounting Pronouncements

The Company identified legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. On January 1, 2003, the Company recorded $289.3 million of asset retirement obligation ("ARO") liabilities; $13.9 million of ARO assets, net of accumulated depreciation; $114.6 million of regulatory assets; and reclassified $1.0 million of accumulated depreciation to the ARO liability. The initial ARO liability recognized includes $266.5 million that pertains to obligations associated with the decommissioning of the Quad Cities nuclear station. The $266.5 million includes a $159.8 million nuclear decommissioning liability that had been recorded at December 31, 2002. The adoption of this statement did not have a material impact on the operations of the regulated entities, as the effects were offset by the establishment of regulatory assets, totaling $114.6 million, pursuant to SFAS 71, "Accounting for the Effects of Certain Types of Regulation".

During the year ended December 31, 2003, the Company recorded, as a regulatory asset and as accretion expense, accretion related to the ARO liability of $16.5 million and $0.1 million, respectively.

In addition, as the result of a decommissioning study, the Company reduced its ARO liability associated with the decommissioning of the Quad Cities nuclear station by $21.9 million. As a result, the ARO liability balance is $284.0 million at December 31, 2003.

In December 2003, the FASB issued FASB Interpretation No. 46R which served to clarify guidance in Financial Interpretation No. 46 ("FIN 46"), and provided additional guidance surrounding the application of 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 sheet as of December 31, 2003. In addition, the associated amounts previously recorded in minority interest and preferred dividends are now recorded as interest expense in the accompanying consolidated statement of operations. For the period from October 1, 2003 to December 31, 2003 the Company has recorded $49.8 million of interest expense related to these securities. In accordance with the requirements of FIN 46R, no amounts prior to adoption on October 1, 2003 have been reclassified. The Company will adopt the provisions of FIN 46R related to non-special purpose entities in the first quarter of 2004, in accordance with the provisions of FIN 46R. The Company is currently evaluating the impact of FIN 46R on several operating joint ventures that the Company currently does not consolidate.

3. Acquisitions

Kern River

On March 27, 2002, the Company acquired Kern River. 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 the first quarter of 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's Amended and Restated Articles of Incorporation.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):


Cash	$	7.7
Properties, plants and equipment		796.8
Goodwill		33.9
Other assets		171.7
Total assets acquired		1,010.1
Current liabilities		(104.3	)
Long-term debt		(482.0	)
Other liabilities		(1.5	)
Total liabilities assumed		(587.8	)
Net assets acquired	$	422.3

Northern Natural Gas Company

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 the third quarter of 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 table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):


Cash	$	1.4
Properties, plants and equipment		1,294.3
Goodwill		416.3
Other assets		340.4
Total assets acquired		2,052.4
Current portion of long-term debt		(450.0	)
Other current liabilities		(195.3	)
Long-term debt		(499.8	)
Other liabilities		(28.2	)
Total liabilities assumed		(1,173.3	)
Net assets acquired	$	879.1

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 each period. 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 each year, nor are the results indicative of the Company's future results of operations (in millions):


	Year Ended December 31,
	2002		2001
Revenue	$	5,299.4	$	5,688.5
Income before cumulative effect of change in accounting principle		285.5		36.9
Net income available to common and preferred shareholders		285.5		32.3

HomeServices' Acquisitions

In 2003, HomeServices separately acquired four real estate companies for an aggregate purchase price of approximately $36.7 million net of cash plus working capital and certain other adjustments. For the year ended December 31, 2002, these real estate companies had combined revenue of approximately $102.9 million on 16,000 closed sides representing $3.6 billion of sales volume. Additionally, HomeServices is obligated to pay a maximum earnout of $5.2 million based on 2004 and 2005 financial performance measures. These purchases were financed using HomeServices' internally generated cash flows and revolving credit facility. In 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of approximately $106.1 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2001, these real estate companies had combined revenue of approximately $356.0 million on 42,000 closed sides representing $13.7 billion of sales volume. Additionally in 2003, HomeServices paid an earnout of $17.3 million based on 2002 financial performance measures. These purchases were financed using HomeServices' internally generated cash flows, revolving credit facility and $40.0 million from MEHC, which was contributed to HomeServices as equity.

Yorkshire Swap

On September 21, 2001, CE Electric UK Ltd, an indirect wholly owned subsidiary of MEHC, and Innogy Holdings plc ("Innogy") executed an agreement to exchange Northern Electric's electricity and gas supply and metering assets for Innogy's 94.75% interest in Yorkshire's electricity distribution business. Northern Electric's supply business was valued at approximately $391.0 million (£268.0 million), including working capital of approximately $14.0 million (£10.0 million). 94.75% of Yorkshire's distribution business was valued at approximately $405.0 million (£278.0 million), including working capital of approximately $58.0 million (£40.0 million). The net cash paid by Northern Electric for the exchange was approximately $14.0 million (£10.0 million).

The 2001 disposition of Northern Electric's supply business created a pre-tax non-recurring gain of $196.7 million and an after-tax gain of $10.8 million which included a write-off of non-deductible goodwill of $504.4 million.

The Company paid $57.4 million, net of cash acquired of $353.8 million and transaction costs, for 94.75% of the Yorkshire electricity distribution business and related indebtedness. The acquisition has been accounted for as a purchase business combination. The results of operations for Yorkshire are included in the Company's results beginning September 21, 2001.

4. Dispositions and Other Items

CE Gas Asset Sale

In May 2002, 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). 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.

Telephone Flat Sale

On October 16, 2001, the Company closed on a transaction that transferred all properties and rights of the Telephone Flat Project, a geothermal development project in northern California to Calpine Corp. The Company recorded a pre-tax gain of $20.7 million and an after-tax gain of $12.2 million on the sale of the Telephone Flat Project.

Western States Sale

On June 30, 2001, the Company closed on a transaction in which the Company sold Western States Geothermal, an indirect wholly owned subsidiary of the Company, to Ormat. The Company recorded a pre-tax gain of $9.8 million and an after-tax gain of $6.4 million on the sale of Western States Geothermal.

Teesside Power Limited ("TPL")

In December 2001, the Company recorded a charge of $20.7 million, net of tax, representing an asset valuation impairment charge under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets" ("SFAS 121") relating to the Company's 15.4% interest in TPL. TPL owns and operates a 1,875 MW combined cycle gas-fired power plant. Enron Corp. ("Enron"), through its subsidiaries, owned a 42.5% interest, operated the plant, and purchased 668 MW of capacity. Enron's subsidiary, which owns and operates TPL, is now in administration and administrators have been appointed to run its business and are attempting to find a buyer.

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 the provision for income taxes.

5. Properties, Plants and Equipment, Net

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


	Depreciation Life		2003			2002
Utility generation and distribution system		10-50	$	9,154,054		$	8,165,140
Interstate pipelines' assets		3-87		3,483,672			2,260,799
Independent power plants		10-30		1,395,782			1,410,170
Mineral and gas reserves and exploration assets		5-30		554,780			500,422
Utility non-operational assets		3-30		429,228			370,811
Other assets		3-10		146,286			131,577
Total operating assets				15,163,802			12,838,919
Accumulated depreciation and amortization				(4,260,643	)		(3,724,917	)
Net operating assets				10,903,159			9,114,002
Construction in progress				277,820			1,170,485
Properties, plants and equipment, net			$	11,180,979		$	10,284,487

Construction in Progress

MidAmerican Energy is constructing two electric generating projects in Iowa. Upon completion, the projects will provide service to regulated retail electricity customers. MidAmerican Energy has obtained regulatory approval to include the actual costs of the generation projects in its Iowa rate base as long as the actual costs do not exceed an agreed upon cap that MidAmerican Energy has deemed to be reasonable. Wholesale sales may also be made from the projects to the extent the power is not needed for regulated retail service.

The second project is currently under construction and will be 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 to be approximately $713 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 May 29, 2003, the Iowa Utilities Board ("IUB") issued an order that approves the ratemaking principles for the plant, and on June 27, 2003, MidAmerican Energy received a certificate from the IUB allowing MidAmerican Energy to construct the plant. On February 12, 2003, MidAmerican Energy executed a contract with Mitsui & Co. Energy Development, Inc. 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. MidAmerican Energy is also seeking an order from the IUB approving construction of the associated transmission facilities.

Kern River completed the construction of its expansion for which it filed an application with the Federal Energy Regulatory Commission on August 1, 2001 (the "2003 Expansion Project") at a total cost of approximately $1.2 billion. The expansion, which was placed into operation on May 1, 2003, increased the design capacity of the existing Kern River pipeline by 885,626 Dth per day to 1,755,626 Dth per day.

6. Investment in CE Generation

Since the sale of 50% of its interests in CE Generation, LLC ("CE Generation") on March 3, 1999, the Company has accounted for CE Generation as an equity investment. The equity investment in CE Generation at December 31, 2003 and 2002 was approximately $209.3 million and $244.9 million, respectively. The following is summarized financial information for CE Generation as of and for the years ended December 31 (in thousands):


	2003		2002		2001
Revenue	$	487,422	$	510,082	$	565,838
Income before cumulative effect of change in accounting principle		37,341		58,314		74,194
Net income		34,874		58,314		58,808
Current assets		124,168		202,490
Total assets		1,708,742		1,865,036
Current liabilities		253,240		148,685
Long-term debt, including current portion		924,563		1,011,220

7. Other Investments

The Williams Companies' Preferred Stock

On March 27, 2002, the Company invested $275.0 million in The Williams Companies, Inc. ("Williams") in exchange for shares of 9 7/8% 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 approximately $288.8 million, plus accrued dividends, all of the shares of its 9-7/8% 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.

CE Casecnan NIA Arbitration Settlement

On October 15, 2003, CE Casecnan Water and Energy Company, Inc. ("CE Casecnan") closed a transaction settling the CE Casecnan NIA Arbitration, which arose from a Statement of Claim made by CE Casecnan, on August 19, 2002, 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. Under the terms of the settlement, CE Casecnan entered into an agreement with NIA which provided for the dismissal with prejudice of all claims by CE Casecnan and counterclaims by NIA in the NIA Arbitration. In connection with the settlement, 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 the other current assets on the December 31, 2003 consolidated balance sheet.

8. Short-Term Debt

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


	2003		2002
MidAmerican Energy commercial paper	$	48,000	$	55,000
HomeServices revolving credit facilities		—		24,750
Other		36		32
Total short-term debt	$	48,036	$	79,782

Parent Company Revolving Credit Facilities

In the second quarter of 2003, the Company terminated its $400 million credit facility. On June 6, 2003, the Company closed on a new $100 million revolving credit facility which expires on June 6, 2006. The facility supports letters of credit of which $73.6 million were outstanding at December 31, 2003. No borrowings were outstanding at December 31, 2003 or 2002. The facility carries a variable interest rate based on Libor and ranged from 2.02% to 2.255% in 2003 and the prior facility ranged from 2.625% to 2.8625% in 2002.

MidAmerican Energy Short-Term Debt

As of December 31, 2003, MidAmerican Energy had in place a $370.4 million revolving credit facility that supports its $250.0 million commercial paper program and its variable rate pollution control revenue obligations. In addition, MidAmerican Energy has a $5.0 million line of credit. As of December 31, 2003 and 2002, commercial paper totaled $48.0 million and $55.0 million, respectively, for MidAmerican Energy. MHC Inc., an indirect wholly owned subsidiary of the Company, has a $4.0 million line of credit under which no borrowings were outstanding at December 31, 2003 or 2002. The commercial paper, bank notes and outstanding line of credit had a weighted average interest rate of 0.98% and 1.29% at December 31, 2003 and 2002, respectively.

HomeServices Revolving Credit Facilities

Upon the expiration of its $65.0 million senior secured revolving credit facility in November 2002, HomeServices entered into a new $125.0 million senior secured revolving credit agreement. The new revolving credit agreement has a term of three years and is secured by a pledge of the capital stock of all of the existing and future subsidiaries of HomeServices. Amounts outstanding under this revolving credit facility 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, 2003 and 2002. No borrowings were outstanding at December 31, 2003 and $24.8 million was outstanding with a weighted average interest rate of 2.6661% at December 31, 2002.

9. Parent Company Senior Debt

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


	2003			2002
6.96% Senior Notes, due 2003	$	—		$	215,000
7.23% Senior Notes, due 2005		260,000			260,000
4.625% Senior Notes, due 2007		199,225			199,044
7.63% Senior Notes, due 2007		350,000			350,000
3.50% Senior Notes, due 2008		449,373			—
7.52% Senior Notes, due 2008		450,000			450,000
7.52% Senior Notes, due 2008 (Series B)		101,267			101,481
5.875% Senior Notes, due 2012		499,898			499,887
8.48% Senior Notes, due 2028		475,000			475,000
Fair value adjustments and other		(6,885	)		(12,025	)
Total Parent Company Senior Debt		2,777,878			2,538,387
Less current portion		—			(215,000	)
Total Long-Term Parent Company Senior Debt	$	2,777,878		$	2,323,387

On May 16, 2003, MEHC issued $450.0 million, net of discount, of its 3.5% Senior Notes with a final maturity on May 15, 2008. The proceeds were used for general corporate purposes. On September 15, 2003, MEHC repaid its $215.0 million, 6.96% Senior Notes.


10.	Parent Company Subordinated Debt/Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

Deconsolidation

In accordance with the provisions of FIN 46R, effective as of October 1, 2003, the Company has recorded its subordinated debt to certain subsidiary finance trusts as long-term debt as a result of the deconsolidation of those trusts pursuant to FIN 46R. In prior years, these amounts were recorded on the consolidated balance sheet as "Company-obligated mandatorily redeemable preferred securities of subsidiary trusts".

The financial terms of MEHC's various subordinated debentures held by such Trusts are essentially identical to the corresponding terms of the trust preferred securities issued by such trusts. The following summarizes the terms and balances of the mandatorily redeemable preferred securities of these unconsolidated trusts.

Finance Trust Subsidiaries

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

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.

The balances presented for December 31, 2003 are recorded in the accompanying consolidated balance sheet as "Parent company subordinated debt". The balances presented for December 31, 2002 are recorded in the accompanying consolidated balance sheet as "Company-obligated mandatorily redeemable preferred securities of subsidiary trusts". The following table presents the balances of such Parent company subordinated debt and Company-obligated mandatorily redeemable preferred securities of subsidiary trusts, respectively (in thousands):


	2003			2002
CalEnergy Capital Trust II — 6.25% preferred securities, due 2012	$	104,645		$	155,538
CalEnergy Capital Trust III — 6.5% preferred securities, due 2027		269,980			269,980
MidAmerican Capital Trust I — 11% preferred securities, due 2010		454,772			454,772
MidAmerican Capital Trust II — 11% preferred securities, due 2012		323,000			323,000
MidAmerican Capital Trust III — 11% preferred securities, due 2012		800,000			950,000
Fair value adjustment		(80,251	)		(89,878	)
Total Parent company subordinated debt (2003)/Company-obligated mandatorily redeemable preferred securities of subsidiary trusts (2002)		1,872,146			2,063,412
Less current portion		(100,000	)		—
Long-term Parent company subordinated debt (2003)/Company- obligated mandatorily redeemable preferred securities of subsidiary trusts (2002)	$	1,772,146		$	2,063,412

Dividends related to the company-obligated mandatorily redeemable preferred securities of subsidiary trusts, which were included in minority interest and preferred dividends on the consolidated statements of operations, for the years ended December 31, 2003, 2002 and 2001 were $170.2 million, $147.7 million and $80.1 million, respectively. For the year ended December 31, 2003 an additional $49.8 million, representing the amount of interest on parent company subordinated debt since the adoption of FIN 46R, was recorded as interest expense in the accompanying consolidated statements of operations.

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). Similarly, 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.

11. 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, 2003, 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 comprise the following at December 31 (in thousands):


	2003			2002
MidAmerican Funding	$	700,000		$	700,000
MidAmerican Energy		1,128,647			1,053,418
CE Electric UK		2,467,214			2,573,589
Kern River		1,276,174			1,277,916
Northern Natural Gas		799,472			799,406
Cordova Funding		214,761			223,762
Salton Sea Funding Corporation		136,384			137,789
CE Casecnan		246,458			287,926
Leyte Projects		172,813			244,961
HomeServices		37,558			39,031
Other, including fair value adjustments		(3,900	)		(5,498	)
Total Subsidiary and Project Debt		7,175,581			7,332,300
Less current portion		(500,941	)		(255,213	)
Total Long-Term Subsidiary and Project Debt.	$	6,674,640		$	7,077,087

MidAmerican Funding

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


	2003		2002
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 comprise the following at December 31 (in thousands):


	2003			2002
Mortgage bonds:
7.125% Series, due 2003	$	—		$	100,000
7.7% Series, due 2004		55,630			55,630
7% Series, due 2005		90,500			90,500
7.375% Series, due 2008		—			75,000
7.45% Series, due 2023		—			6,940
6.95% Series, due 2025		—			12,500
Pollution control revenue obligations:
5.75% Series, due periodically through 2003		—			4,320
6.7% Series, due 2003		—			1,000
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, 1.26% and 1.64%		37,600			37,600
Due 2023 (secured by general mortgage bond, 1.26% and 1.64%		28,295			28,295
Due 2023, 1.26% and 1.64%		6,850			6,850
Due 2024, 1.26% and 1.64%		34,900			34,900
Due 2025, 1.26% and 1.64%		12,750			12,750
Notes:
6.375% Series, due 2006		160,000			160,000
5.125% Series, due 2013		275,000			—
6.75% Series, due 2031		400,000			400,000
Obligations under capital lease		2,060			2,161
Unamortized debt premium and discount, net		(4,968	)		(5,058	)
Total MidAmerican Energy	$	1,128,647		$	1,053,418

On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% notes due in 2031. The proceeds were used to refinance existing debt and preferred securities and for other corporate purposes. On March 11, 2002, MidAmerican Energy redeemed its MidAmerican Energy-obligated mandatorily redeemable preferred securities of subsidiary trust at 100% of the principal amount plus accrued interest.

On January 14, 2003, MidAmerican Energy issued $275 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 subsidiares' long-term debt comprise the following at December 31 (in thousands):


	2003		2002
6.853% Senior Notes, due 2004	$	117,112	$	124,732
8.625% Bearer bonds, due 2005		178,877		161,451
6.995% Senior Notes, due 2007		236,174		236,081
6.496% Yankee Bonds, due 2008		281,149		300,185
Variable Rate Reset Trust Securities, due 2020 (4.39% and 5.04%)		287,539		260,028
8.875% Bearer bonds, due 2020		178,644		161,360
9.25% Eurobonds, due 2020		458,187		419,145
7.25% Sterling Bonds, due 2022		351,242		316,829
7.25% Eurobonds, due 2028		352,768		344,082
8.08% Trust Securities, due 2038		—		249,696
CE Gas Credit Facility, 6.67%		25,522		—
Total CE Electric UK	$	2,467,214	$	2,573,589

On February 15, 2005, the Variable Rate Reset Trust Securities may be remarketed at the option of the original underwriter at a fixed rate of interest through the maturity date or, CE Electric UK's subsidiary may elect a floating rate obligation for up to one year at which time the obligation would be remarketed at a fixed rate of interest through 2020, or redeemed by Yorkshire at a premium.

On June 9, 2003, Yorkshire Power Group Limited, an indirect wholly owned subsidiary of CE Electric UK, completed the redemption in full of the outstanding shares of the 8.08% Trust Securities, due June 30, 2038, and paid $243.4 million in principal amount plus accrued distributions. The redemption price was paid to holders of the trust security on the redemption date.

During 2003, CE Electric UK and its subsidiaries purchased and retired approximately $50.0 million of outstanding indebtedness.

Kern River

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


	2003		2002
Construction financing facility	$	—	$	789,916
6.676% Senior Notes, due 2016		464,000		488,000
4.893% Senior Notes, due 2018		812,174		—
Total Kern River	$	1,276,174	$	1,277,916

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 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the approximately $815 million of outstanding borrowings under Kern River's $875 million credit facility. Kern River entered into this credit facility in 2002 to finance the construction of the 2003 Expansion Project. The credit facility was canceled and a completion guarantee issued by MEHC was terminated.

Northern Natural Gas

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


	2003			2002
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		(528	)		(594	)
Total Northern Natural Gas	$	799,472		$	799,406

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 comprise the following at December 31 (in thousands):


	2003		2002
8.48% Senior Secured Bonds, due 2019	$	12,175	$	12,685
8.64% Senior Secured Bonds, due 2019		89,260		93,001
8.79% Senior Secured Bonds, due 2019		29,885		31,137
8.82% Senior Secured Bonds, due 2019		55,476		57,801
9.07% Senior Secured Bonds, due 2019		27,965		29,138
Total Cordova Funding	$	214,761	$	223,762

MEHC has guaranteed 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 also provides a debt service reserve guarantee in an amount equal to the principal, premium, if any, and interest payment due on the bonds on the next scheduled payment date which was equal to $13.5 million at December 31, 2003.

As of December 31, 2003, 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.

Salton Sea Funding

Salton Sea Funding Corporation ("SSFC"), an indirect wholly owned subsidiary of CE Generation, had a debt balance of $463.6 million at December 31, 2003. CalEnergy Minerals LLC ("Minerals"), a wholly owned indirect subsidiary of MEHC, which owns a zinc facility, is one of several guarantors of the Salton Sea Funding Corporation's debt. As a result of a note allocation agreement, Minerals is primarily responsible for approximately $136.4 million of the 7.475% Senior Secured Series F Bonds due November 30, 2018 ("Series F Bonds"). In 1999, MEHC guaranteed a specified portion of the scheduled debt service on the Series F Bonds equal to this current principal amount of approximately $136.4 million and associated interest.

On January 30, 2004, SSFC announced its election to redeem an aggregate principal amount of $136.4 million of the 7.475% Senior Secured Series F Bonds due November 30, 2018, pro rata, at a redemption price of 100% of such aggregate outstanding principal amount, plus accrued interest to the date of redemption. The trustee delivered a redemption notice to the holders of the bonds on January 29, 2004. The record date for the redemption is February 15, 2004 and the redemption is expected to be completed on March 1, 2004. SSFC expects to make a demand on MEHC for the full amount remaining under MEHC's 1999 guarantee of the Series F Bonds in order to fund the redemption. Upon the expected demand and payment under MEHC's guarantee, MEHC will no longer have any liability with respect to its guarantee.

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 comprise the following at December 31 (in thousands):


	2003		2002
11.45% Senior Secured Series A Notes, due in 2005	$	91,250	$	125,000
11.95% Senior Secured Series B Bonds, due in 2010		155,208		162,926
Total Casecnan	$	246,458	$	287,926

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 comprise the following at December 31 (in thousands):


	2003		2002
Mahanagdong Project 6.92% Term Loan, due 2007	$	72,151	$	92,766
Mahanagdong Project 7.60% Term Loan, due 2007		16,000		20,571
Malitbog Project 3.67% and 3.84%, due 2005		26,378		40,890
Malitbog Project 9.176% Term Loan, due 2006		14,628		22,677
Upper Mahiao Project 4.42%, due 2003		—		5,000
Upper Mahiao Project 5.95% Term Loan, due 2006		43,656		63,057
Total Leyte Projects	$	172,813	$	244,961

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 was equal to $40.3 million and $47.7 million at December 31, 2003 and 2002, respectively.

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, 2003 and 2002, the balance of the HomeServices Senior Notes was $35.0 million.

In addition to the senior notes, HomeServices' has outstanding notes, with varying interest rates, totaling $2.6 million and $4.0 million at December 31, 2003 and 2002, respectively.

Annual Repayments of Debt

The annual repayments of debt for the years beginning January 1, 2004 and thereafter are as follows (in thousands):


	2004		2005		2006		2007		2008		Thereafter			Total
Parent, Subsidiary and Project loans:
Parent Company Senior Debt	$	—	$	260,000	$	—	$	550,000	$	1,000,000	$	967,878		$	2,777,878
Parent Company Subordinated Debt		100,000		188,544		234,021		234,021		234,021		881,539			1,872,146
MidAmerican Funding		—		—		—		—		—		700,000			700,000
MidAmerican Energy		56,151		90,500		160,000		1,000		—		820,996			1,128,647
CE Electric UK		117,112		178,877		—		236,174		281,149		1,653,902			2,467,214
Kern River		61,366		62,784		66,128		69,472		72,816		943,608			1,276,174
Northern Natural Gas		—		100,000		—		—		150,000		549,472			799,472
Cordova Funding		8,100		7,875		4,500		4,163		4,725		185,398			214,761
Salton Sea Funding Corporation		136,384		—		—		—		—		—			136,384
CE Casecnan		49,360		54,752		36,016		37,730		37,730		30,870			246,458
Leyte Projects		67,148		63,035		30,037		12,593		—		—			172,813
HomeServices		5,320		5,000		5,000		5,000		5,000		12,238			37,558
Other, including fair value adjustments		—		—		—		—		—		(3,900	)		(3,900	)
Total Parent, Subsidiary and Project Loans	$	600,941	$	1,011,367	$	535,702	$	1,150,153	$	1,785,441	$	6,742,001		$	11,825,605

Fair Value

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 that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates.

12. Income Taxes

Provision for income taxes was comprised of the following (in thousands):


	Year Ended December 31,
	2003			2002			2001
Current:
Federal	$	(78,066	)	$	46,714		$	51,025
State		3,565			14,516			2,669
Foreign		88,150			54,586			43,450
		13,649			115,816			97,144
Deferred:
Federal		155,237			(7,073	)		(14,004	)
State		14,577			(9,675	)		(342	)
Foreign		67,508			520			167,266
		237,322			(16,228	)		152,920
Total	$	250,971		$	99,588		$	250,064

A reconciliation of the federal statutory tax rate to the effective tax rate applicable to income before provision for income taxes follows:


	2003			2002			2001
Federal statutory rate		35.0	%		35.0	%		35.0	%
Investment and energy tax credits		(0.5	)		(0.7	)		(1.0	)
State taxes, net of federal tax effect		1.4			1.2			3.2
Goodwill amortization		—			—			5.9
Dividends on preferred securities of subsidiary trusts		(7.0	)		(8.1	)		(6.1	)
Tax effect of foreign income		0.5			(4.8	)		(2.5	)
Non-recurring items on CE Electric UK,
net of tax effect of foreign income		(0.5	)		(8.1	)		19.2
Dividends received deduction		(1.2	)		(1.8	)		(2.6	)
Other items, net		1.8			2.8			(1.5	)
Effective tax rate		29.5	%		15.5	%		49.6	%

The Internal Revenue Service ("IRS") regularly examines the Company's federal income tax returns and, in the course of which, may propose adjustments to the Company's federal income tax liability reported on such returns. Tax years 1995 through 2001 are currently under review. The Company's management does not expect that the outcome of any proposed adjustments presented to date by the IRS, individually or collectively, will have a material adverse effect on the Company's financial position, results of operations, or cash flows.

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


	2003			2002
Properties, plants and equipment, net	$	1,721,842		$	1,325,228
Income taxes recoverable through future rates		142,597			159,411
Employee benefits		43,005			65,537
Reacquired debt		5,665			4,914
Fuel cost recoveries		12,864			—
Other		—			121
		1,925,973			1,555,211

Minimum pension liability adjustment		(147,279	)		(140,854	)
Revenue sharing accruals		(64,192	)		(48,861	)
Accruals not currently deductible for tax purposes		(37,672	)		(59,083	)
Nuclear reserve and decommissioning		(35,955	)		(28,411	)
Deferred income		(37,819	)		(21,733	)
Fuel cost recoveries		—			(9,558	)
NOL and credit carryforwards		(161,659	)		(8,290	)
Other		(8,253	)		—
		(492,829	)		(316,790	)
Net deferred income taxes	$	1,433,144		$	1,238,421

13. Preferred Securities of Subsidiaries

The total outstanding cumulative preferred securities of MidAmerican Energy not subject to mandatory redemption requirements may be redeemed at the option of MidAmerican Energy at prices which, in the aggregate, total $32.6 million. The aggregate total the holders of all preferred securities outstanding at December 31, 2003 and 2002, are entitled to upon involuntary bankruptcy is $31.8 million plus accrued dividends. Annual dividend requirements for all preferred securities outstanding at December 31, 2003, total $1.3 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 Company's Public Electricity Supply License, was $56.0 million as of December 31, 2003 and 2002.

During 2002, MidAmerican Energy redeemed all $26.7 million of its $7.80 Series Preferred Shares.

14. 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, share 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.

15. Stock Transactions

As of December 31, 2003, 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.

16. Accounting for Derivatives

Currency Exchange Rate Risk

interest rate to a fixed rate in Sterling. For the $117.1 million of 6.853% Senior Notes outstanding at December 31, 2003, the agreements extend until maturity on December 30, 2004 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.744%. For the $236.2 million of 6.995% Senior Notes, 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, 2003 is approximately $16.0 million 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 the $281.1 million of the 6.496% Yankee Bonds outstanding at December 31, 2003, 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, 2003 is approximately $62.6 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.

17. Regulatory Matters

MidAmerican Energy

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 a 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. An amount equal to the regulatory liability is recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. Future depreciation will be reduced as a result of the credit applied to generating plant balances as the regulatory liability is reduced. The liability is being reduced as it is credited against plant in service in amounts equal to the allowance for funds used during construction associated with generating plant additions. Interest expense is accrued on the portion of the regulatory liability related to prior years.

and a premium of 12.5% for 2005 and 2006. The two-year average above which sharing must occur for 2003 was 13.73%. The law allows MidAmerican Energy to mitigate the sharing of earnings above the threshold return on common equity through accelerated recovery of electric assets.

CE Electric UK

Most revenue of each Distribution License Holder ("DLH") is controlled by a distribution price control formula. The current formula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where the Retail Price Index ("RPI") reflects the average of the 12-month inflation rates recorded for each month in the previous July to December period. The distribution price control formula also reflects an adjustment factor ("Xd") which was established by the regulatory body, the Office of Gas and Electricity Markets ("Ofgem"), at the last price control review (and continues to be set) at 3%. The formula also takes account of the changes in system electrical losses, the number of customers connected and the voltage at which customers receive the units of electricity distributed. This 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 a predetermined increase in 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 lifetime of the price control, cost savings or additional costs have a direct impact on profit.

Northern Natural Gas

18. Pension Commitments

Domestic Operations

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering MEHC and its domestic energy subsidiaries. Benefit obligations under the plans are based on participants' compensation, years of service and age at retirement. Funding to an external trust is based upon the actuarially determined costs of the plans and the requirements of the Internal Revenue Code and the Employee Retirement Income Security Act. The Company also maintains noncontributory, nonqualified supplemental executive retirement plans for active and retired participants.

MidAmerican Energy also currently sponsors certain postretirement health care and life insurance benefits covering all retired domestic employees of MEHC and its domestic energy subsidiaries. Under the plan, substantially all of MEHC's and its domestic energy subsidiaries' employees may become eligible for these benefits if they reach retirement age while working for the Company. However, the Company retains the right to change these benefits anytime at its discretion, subject to provisions in the union contract.

Net periodic pension, supplemental retirement and postretirement benefit costs included the following components for the Company and the aforementioned affiliates 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.

Components of net periodic benefit cost (in thousands):


	Pension Cost									Postretirement Cost
	2003			2002			2001			2003			2002			2001
Service cost	$	24,693		$	20,235		$	18,114		$	8,175		$	6,028		$	4,357
Interest cost		34,533			34,177			33,027			16,065			13,928			10,418
Expected return on plan assets		(38,396	)		(38,213	)		(36,326	)		(6,008	)		(4,880	)		(4,032	)
Amortization of net transition obligation		(2,591	)		(2,591	)		(2,591	)		4,110			4,110			4,110
Amortization of prior service cost		2,761			2,729			2,729			593			425			425
Amortization of prior year (gain) loss		1,483			(2,482	)		(3,894	)		3,716			2,385			332
Regulatory expense		3,320			6,639			—			—			—			—
Net periodic cost	$	25,803		$	20,494		$	11,059		$	26,651		$	21,996		$	15,610

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


	2003			2002			2001			2003			2002			2001
Discount rate		5.75	%		5.75	%		6.50	%		5.75	%		5.75	%		6.50	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%

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


	2003			2002			2001			2003			2002			2001
Discount rate		5.75	%		6.50	%		7.00	%		5.75	%		6.50	%		7.00	%
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	%

Assumed health care cost trend rates at December 31:


	2003			2002
Health care cost trend rate assumed for next year		11.00	%		9.75	%
Rate that the cost trend rate gradually declines to		5.00	%		5.25	%
Year that the rate reaches the rate it is assumed to remain at		2010			2006

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:


	One Percentage-Point Increase		One Percentage-Point Decrease
Effect on total service and interest cost	$	5,484	$	(4,136	)
Effect on postretirement benefit obligation	$	47,583	$	(37,761	)

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 Consolidated Balance Sheets as of December 31(in thousands):


	Pension Benefits						Postretirement Benefits
	2003			2002			2003			2002
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year	$	467,773		$	515,890		$	122,655		$	81,129
Employer contributions		5,044			4,681			32,566			24,034
Participant contributions		—			—			6,371			4,505
Actual return on plan assets		105,438			(27,376	)		15,853			(4,528	)
Acquisition		—			—			—			32,500
Benefits paid		(26,687	)		(25,422	)		(19,596	)		(14,985	)
Fair value of plan assets at end of year	$	551,568		$	467,773		$	157,849		$	122,655

Reconciliation of benefit obligation:
Benefit obligation at beginning of year	$	593,179		$	518,208		$	291,441		$	194,917
Service cost		24,693			20,235			8,175			6,028
Interest cost		34,533			34,177			16,065			13,928
Participant contributions		—			—			6,371			4,505
Plan amendments		—			520			—			2,205
Actuarial (gain) loss		(5,670	)		45,461			(5,023	)		31,743
Acquisition		—			—			—			53,100
Benefits paid		(26,687	)		(25,422	)		(19,596	)		(14,985	)
Benefit obligation at end of year	$	620,048		$	593,179		$	297,433		$	291,441

Funded status	$	(68,480	)	$	(125,406	)	$	(139,584	)	$	(168,786	)
Amounts not recognized:
Unrecognized net (gain) loss		(12,907	)		61,289			83,509			102,095
Unrecognized prior service cost		17,915			20,676			5,451			6,043
Unrecognized net transition obligation (asset)		(792	)		(3,383	)		36,992			41,102
Net amount recognized in the Consolidated Balance Sheets	$	(64,264	)	$	(46,824	)	$	(13,632	)	$	(19,546	)

Amounts recognized in the Consolidated Balance Sheets consist of
Prepaid benefit cost	$	39		$	11,825		$	—		$	1,493
Accrued benefit liability		(100,490	)		(99,392	)		(13,632	)		(21,039	)
Intangible assets		17,367			20,082			—			—
Regulatory assets		18,820			20,661			—			—
Net amount recognized	$	(64,264	)	$	(46,824	)	$	(13,632	)	$	(19,546	)

The accumulated benefit obligation for all defined benefit pension plans was $554.6 million and $526.7 million at December 31, 2003 and 2002, respectively. The projected benefit obligation (included in the table above), accumulated benefit obligation and fair value of plan assets for the supplemental executive retirement plan which had an accumulated benefit obligation in excess of plan assets were $105.1 million, $100.5 million and $ — as of December 31, 2003 and $103.4 million, $99.1 million and $ — as of December 31, 2002, respectively. A minimum liability must be recognized for those plans whose accumulated benefit obligation exceeds plan assets.

Although the supplemental executive retirement plan had no assets as of December 31, 2003, 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 fair value of these assets is not included in the plan asset table below. The fair value of the Rabbi trust investments was $88.1 million and $76.2 million at December 31, 2003 and 2002, 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 Benefits 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 allocation at December 31, 2003 and 2002, are as follows:


	Percentage of Plan Assets
	at December 31						Target Range
Asset Category	2003			2002			Target Range
Equity securities		70	%		60	%		65-75	%
Debt securities		23			33			20-30
Real estate		7			7			0-10
Other		—			—			0-5
Total		100	%		100	%

The Company's postretirement benefit plan asset allocation at December 31, 2003, and 2002, are as follows:


	Percentage of Plan Assets
	at December 31						Target Range
Asset Category	2003			2002			Target Range
Equity securities		49	%		34	%		45-55	%
Debt securities		48			48			45-55
Other		3			18			0-10
Total		100	%		100	%

Cash Flows

Employer contributions to the domestic pension and postretirement plans are currently expected to be $5.1 million and $27.6 million, respectively, for 2004 based on current regulations which are subject to change. 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 $12.4 million, $9.8 million and $8.6 million for 2003, 2002 and 2001, 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 have yet to be promulgated, and accordingly, the Company cannot determine precisely how it will implement the Medicare Act's provisions. Additionally, accounting guidance regarding the recognition of the impacts of the Medicare Act is pending. Accordingly, the Company continues to evaluate its options and cannot predict the

magnitude or timing of any resulting costs savings. As permitted by FASB Staff Position 106-1, the Company has elected to defer recognizing the effects of the Medicare Act in its post-retirement plan accounting at December 31, 2003.

United Kingdom Operations

CE Electric UK, through a wholly-owned subsidiary, participates 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 costs included the following components for CE Electric UK for the years ended December 31. For purposes of calculating the expected return on pension plant 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.

Components of net periodic pension cost (in thousands):


	Pension Cost
	2003			2002			2001
Service cost	$	9,485		$	8,718		$	7,781
Interest cost		62,632			56,817			51,440
Expected return on plan assets		(89,124	)		(85,927	)		(78,354	)
Amortization of prior service cost		1,472			1,202			—
Curtailment loss and foreign exchange		537			6,463			7,061
Net periodic benefit	$	(14,998	)	$	(12,727	)	$	(12,072	)

As a result of the distribution price reviews in 1999, CE Electric UK implemented a review of staffing requirements primarily in its distribution business. Following discussions with the trade unions, CE Electric UK put in place a workforce reduction program. The pension curtailment related to this workforce reduction program was $ - million, $6.5 million and $7.1 million in 2003, 2002 and 2001, respectively.

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


	2003			2002			2001
Discount rate		5.5	%		5.75	%		5.75	%
Rate of compensation increase		2.75	%		2.5	%		2.5	%

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


	2003			2002			2001
Discount rate		5.5	%		5.75	%		5.75	%
Expected return on plan assets		7.00	%		7.00	%		7.7	%
Rate of compensation increase		2.75	%		2.5	%		2.5	%


	Pension Benefits
	2003			2002
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year	$	976,427		$	1,070,657
Employer contributions		14,391			3,607
Participant contributions		4,742			3,006
Actual return on plan assets		152,246			(144,298	)
Benefits paid		(57,726	)		(57,719	)
Foreign currency exchange rate changes		116,136			101,174
Fair value of plan assets at end of year	$	1,206,216		$	976,427
Reconciliation of benefit obligation:
Benefit obligation at beginning of year	$	1,102,730		$	974,079
Service cost		9,485			8,718
Interest cost		62,632			56,817
Participant contributions		4,742			3,006
Benefits paid		(57,726	)		(57,719	)
SFAS 88 Curtailment		—			5,712
Prior service cost		—			17,286
Experience gain and change of assumptions		83,890			(11,574	)
Foreign currency exchange rate changes		128,834			106,405
Benefit obligation at end of year	$	1,334,587		$	1,102,730
Funded status		(128,371	)	$	(126,303	)
Unrecognized net loss		507,039			465,211
Net amount recognized in the Consolidated Balance Sheets	$	378,668		$	338,908
Amounts recognized in the Consolidated Balance Sheets consist of:
Prepaid benefit cost	$	378,668		$	338,908
Accrued benefit liability		(496,147	)		(457,317	)
Intangible assets		16,604			16,433
Accumulated other comprehensive income		479,543			440,884
Net amount recognized	$	378,668		$	338,908

The accumulated benefit obligation for the defined benefit pension plan was $1.3 billion and $1.1 billion at December 31, 2003 and 2002, respectively.

The Company recorded a minimum pension liability as of December 31, 2003 and 2002 in the amount of $479.5 million and $440.9 million, respectively. The pension liability resulted from the declining market value of the pension plan assets during 2002 combined with a lower market interest rate used to value the plan's liabilities. As of December 31, 2003 and 2002, 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, 2003 and 2002 plus the prepaid asset balance. A charge equal to the excess was recorded to the Company's stockholder's equity, net of income tax benefits, as a component of comprehensive loss in the amount of $27.1 million and $308.6 million in 2003 and 2002, 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 comprises the following at December 31:


	Percentage of Plan Assets
	at December 31
Asset Category	2003			2002
Equity securities		64	%		62	%
Debt securities		26			27
Real estate		9			10
Other		1			1
Total		100	%		100	%

Cash Flows

Employer contributions to fund the ongoing liabilities of the UK Plan are expected to be approximately $14.0 million in 2004. The next valuation of the UK Plan will take place as of March 31, 2004 and the results will be known later in the year. This valuation will set a revised level of contributions for the next three years. If the valuation results in a deficit in the UK Plan then an appropriate level of funding to address the deficit will be agreed in accordance with the UK Plan rules. The overall level of contributions paid by the employer is expected to be one of the factors considered by the regulator in setting the revised allowed prices which will take effect from April 1, 2005.

19. Commitments and Contingencies

Fuel, Energy and Operating Lease Commitments

MidAmerican Energy has supply and related transportation contracts for its fossil fueled generating stations. As of December 31, 2003, the contracts, with expiration dates ranging from 2004 to 2010, require minimum payments of $83.3 million, $69.9 million, $54.5 million, $50.2 million and $16.1 million for the years 2004 through 2008, respectively, and $31.0 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 contact for a natural gas-fired generating plant. The contract, which expires in 2012, requires minimum payments of $0.8 million for 2004 and $6.2 million for each year thereafter.

MidAmerican Energy also has contracts with non-affiliated companies to purchase electric capacity. As of December 31, 2003, the contracts, with expiration dates ranging from 2004 to 2028, require minimum payments of $38.6 million, $3.6 million, $2.3 million, $2.2 million and $2.2 million for the years 2004 through 2008, respectively, and $40.1 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, 2003, the minimum commitments under these contracts were $56.3 million, $43.8 million, $18.0 million, $13.9 million and $4.2 million for the years 2004 through 2008, respectively, and $12.5 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, 2003, the maximum amount of such guarantees specified in these leases totaled $31.0 million. These guarantees are not reflected on the Consolidated Balance Sheets.

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. The minimum payments under these leases are $53.1 million, $46.9 million, $41.0 million, $37.1 million and $27.0 million for the years 2004 through 2008, respectively, and $85.0 million for the total of the years thereafter.

Manufactured Gas Plants

The United States Environmental Protection Agency ("EPA") and the state environmental agencies have determined that contaminated wastes remaining at decommissioned manufactured gas plant facilities may pose a threat to the public health or the environment if such contaminants are in sufficient quantities and at such concentrations as to warrant remedial action.

The estimated liability is determined through a site-specific cost evaluation process. The estimate includes incremental direct costs of remediation, site monitoring costs and costs of compensation to employees for time expected to be spent directly on the remediation effort. The estimated recorded liabilities for these properties are based upon preliminary data. Thus, actual costs could vary significantly from the estimates. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action and changes in technology relating to remedial alternatives. Insurance recoveries have been received for some of the sites under investigation. Those recoveries are intended to be used principally for accelerated remediation, as specified by the IUB and are recorded as a regulatory liability.

Air Quality

The EPA has in recent years implemented more stringent standards for ozone and fine particulate matter. Designations regarding attainment of the eight-hour ozone standard have recently been reviewed by the EPA, and the EPA has concluded that the entire state of Iowa is in attainment of the standards. On December 4, 2003, the EPA announced the development of its Interstate Air Quality Rule, a proposal to require coal-burning power plants in 29 states 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 for the regulation of

mercury from coal-fired utilities as necessary to protect public health. 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 rule by December 2004. Any of these new or stricter standards could, in whole or in part, be superceded 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.

source will not trigger the NSR provisions of the Clean Air Act. After the NSR changes were announced, the EPA's enforcement branch indicated it would apply the clarified routine repair, maintenance and replacement rules to its pending investigation. A number of states and local air districts have challenged the EPA's clarification of the rule and a panel of the U.S. Circuit Court of Appeals for the District of Columbia issued an order on December 24, 2003 staying the EPA's implementation of its clarification of the equipment replacement rule.

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 2003 dollars, is $260 million and is the asset retirement obligation for Quad Cities Station. Refer to Note (1)(j) for a discussion of asset retirement obligations. MidAmerican Energy has established external 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 Investments and Nonregulated Property, Net.

MidAmerican Energy's depreciation and amortization expense included costs for Quad Cities Station nuclear decommissioning of $8.3 million for each of the years 2003, 2002 and 2001. The regulatory provision charged to expense is equal to the funding that is being collected in Iowa rates. Realized and unrealized gains and (losses) on the assets in the trust fund were $16.1 million, $(6.9) million and $(3.1) million for 2003, 2002 and 2001, respectively.

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 (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 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 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 $7.6 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 Nuclear Regulatory Commission 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.

Natural Gas Commodity Litigation

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 the Company. 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 the Company. 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. Unless extended by agreement of the parties or by court order, MidAmerican Energy's answer and/or responsive pleading in this matter is due February 19, 2004. MidAmerican Energy will coordinate with the other defendants and vigorously defend the allegations against it.

Philippines

CE Casecnan Construction Contract Arbitration

In 2001, the Contractor filed a Request for Arbitration (and two supplements) with the International Chamber of Commerce ("ICC") seeking schedule relief of up to 153 days, compensation for alleged

CE Casecnan Stockholder Litigation

20. Segment Information:

The Company has identified seven reportable segments principally based on management structure: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK, CalEnergy Generation-Domestic, CalEnergy Generation-Foreign, and HomeServices. Information related to the Company's reportable operating segments is shown below (in thousands).


	Year Ended December 31,
	2003			2002			2001
Operating revenue:
MidAmerican Energy	$	2,600,239		$	2,240,879		$	2,388,650
Kern River		260,182			127,254			—
Northern Natural Gas		482,156			176,880			—
CE Electric UK		829,993			795,366			1,443,997
CalEnergy Generation – Domestic		45,750			38,546			37,299
CalEnergy Generation – Foreign		326,454			326,316			203,482
HomeServices		1,476,569			1,138,332			641,934
Segment operating revenue		6,021,343			4,843,573			4,715,362
Corporate/other		(73,119	)		(49,563	)		(18,581	)
Total operating revenue	$	5,948,224		$	4,794,010		$	4,696,781
Depreciation and amortization:
MidAmerican Energy	$	281,001		$	269,412		$	286,590
Kern River		36,771			17,165			—
Northern Natural Gas		52,716			18,151			—
CE Electric UK		125,000			116,792			133,865
CalEnergy Generation – Domestic		16,020			8,714			5,439
CalEnergy Generation – Foreign		87,928			88,036			66,315
HomeServices		17,560			22,072			17,201
Segment depreciation and amortization		616,996			540,342			509,410
Corporate/other		(7,107	)		(14,440	)		29,292
Total depreciation and amortization	$	609,889		$	525,902		$	538,702
Interest expense, net:
MidAmerican Energy	$	118,809		$	119,225		$	113,980
Kern River		61,979			33,036			—
Northern Natural Gas		55,833			22,987			—
CE Electric UK		171,767			183,472			112,308
CalEnergy Generation – Domestic		30,333			20,913			10,835
CalEnergy Generation – Foreign		59,603			68,338			30,875
HomeServices		3,864			4,256			3,884
Segment interest expense, net		502,188			452,227			271,882
Corporate/other		239,160			157,683			140,912
Total interest expense, net	$	741,348		$	609,910		$	412,794


	Year Ended December 31,
	2003			2002			2001
Income before provisions for income taxes:
MidAmerican Energy	$	268,670		$	241,005		$	211,300
Kern River		133,720			60,700			—
Northern Natural Gas		127,307			42,882			—
CE Electric UK		288,720			266,755			173,816
CalEnergy Generation – Domestic		(25,510	)		(4,963	)		46,765
CalEnergy Generation – Foreign		179,546			149,915			94,542
HomeServices		113,537			69,979			42,945
Segment income before provision for income taxes		1,085,990			826,273			569,368
Corporate/other		(236,198	)		(183,175	)		(65,484	)
Total income before provision for income taxes	$	849,792		$	643,098		$	503,884
Provision for income taxes:
MidAmerican Energy	$	110,078		$	99,782		$	95,688
Kern River		51,319			23,014			—
Northern Natural Gas		50,599			16,947			—
CE Electric UK		91,539			25,245			163,253
CalEnergy Generation – Domestic		(18,183	)		(15,203	)		2,706
CalEnergy Generation – Foreign		76,493			37,577			29,712
HomeServices		43,587			28,207			15,953
Segment provision for income taxes		405,432			215,569			307,312
Corporate/other		(154,461	)		(115,981	)		(57,248	)
Total provision for income taxes	$	250,971		$	99,588		$	250,064
Capital expenditures:
MidAmerican Energy	$	378,530		$	358,194		$	252,615
Kern River		361,477			769,464			—
Northern Natural Gas		104,400			62,409			—
CE Electric UK		301,896			222,622			176,464
CalEnergy Generation – Domestic		17,845			61,920			52,940
CalEnergy Generation – Foreign		8,497			7,830			83,954
HomeServices		18,311			18,273			9,878
Segment capital expenditures		1,190,956			1,500,712			575,851
Corporate/other		71			7,373			901
Total capital expenditures	$	1,191,027		$	1,508,085		$	576,752


	As of December 31,
	2003		2002		2001
Identifiable assets:
MidAmerican Energy	$	6,596,849	$	6,411,143	$	6,215,968
Kern River		2,200,201		1,797,850		—
Northern Natural Gas		2,167,621		2,162,367		—
CE Electric UK		5,038,880		4,714,459		4,340,147
CalEnergy Generation – Domestic		865,223		873,357		870,664
CalEnergy Generation – Foreign		949,237		974,852		950,035
HomeServices		567,736		488,324		322,552
Segment identifiable assets		18,385,747		17,422,352		12,699,366
Corporate/other		782,442		1,012,568		295,219
Total identifiable assets	$	19,168,189	$	18,434,920	$	12,994,585
Long-lived assets:
MidAmerican Energy	$	5,524,279	$	5,385,328	$	5,247,817
Kern River		2,010,113		1,682,934		—
Northern Natural Gas		1,809,623		1,818,469		—
CE Electric UK		4,489,306		3,936,598		3,650,385
CalEnergy Generation – Domestic		593,580		594,282		571,404
CalEnergy Generation – Foreign		621,674		724,908		805,050
HomeServices		418,999		384,899		262,175
Segment long-lived assets		15,467,574		14,527,418		10,536,831
Corporate/other		19,048		15,201		7,019
Total long-lived assets	$	15,486,622	$	14,542,619	$	10,543,850

The remaining differences from the segment amounts to the consolidated amounts described as "Corporate/Other" relate principally to the corporate functions including administrative costs, corporate cash and related interest income, corporate interest expenses, intersegment eliminations, and fair value adjustments relating to acquisitions.

The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2003 and 2002 (in thousands):


	MidAmerican Energy			Kern River		Northern Natural Gas			CE Electric UK			Cal Energy Generation Domestic			Home- Services			Total
Balance, January 1, 2002	$	2,160,004		$	—	$	—		$	1,104,262		$	142,726		$	231,554		$	3,638,546
Goodwill from acquisitions during the year		—			32,547		414,721			56,626			—			108,914			612,808
Goodwill written off related to the sale of a business unit		—			—		—			(49,587	)		—			—			(49,587	)
Other goodwill adjustments ⁽¹⁾		(10,722	)		—		—			84,020			(16,286	)		(647	)		56,365
Balance, December 31, 2002		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

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

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 of MEHC, 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, 2003. Based on that evaluation, the Company's management, including the Chief Executive Officer and Chief Financial Officer of MEHC, concluded that the Company's disclosure controls and procedures were effective. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls.

100

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 and Chief Administrative Officer
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, 2004, with respect to each of the foregoing officers and directors:

DAVID L. SOKOL, 47, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been CEO 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, 41, 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 he 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, 37, 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, 45, 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 and Chief Administrative Officer. Mr. Hartje has been with MidAmerican Energy and its predecessor companies since 1973. In that time, he has held a number of positions, including General Counsel and Corporate Secretary, District Vice President for southwest Iowa operations, and Vice President, Corporate Communications.

WARREN E. BUFFETT, 73, 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 Inc. Mr. Buffett is a Director of the Coca-Cola Company, the Gillette Company and The Washington Post Company.

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WALTER SCOTT, JR., 72, 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 Inc., 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, 54, Director. Mr. Hamburg has been a director of MEHC since March 2000. He has served as Vice President – Chief Financial Officer of Berkshire Hathaway Inc. since October 1, 1992 and Treasurer since June 1, 1987, his date of employment with Berkshire Hathaway Inc.

W. DAVID SCOTT, 42, 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, 69, 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, 59, 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, 63, 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, 51, 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.

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, 2003, which

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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 Compensation		All Other Comp⁽²⁾
David L. Sokol		2003	$	800,000	$	2,750,000	$	—	$	7,960
Chairman and		2002		800,000		2,750,000		27,122,550		7,960
Chief Executive Officer		2001		750,000		2,400,000		—		33,033

Gregory E. Abel		2003		669,011		2,200,000		—		7,690
President and		2002		540,000		2,200,000		—		7,636
Chief Operating Officer		2001		520,000		1,150,000		—		23,657

Patrick J. Goodman		2003		273,570		285,000		—		7,392
Senior Vice President and		2002		248,000		365,000		209,560		7,353
Chief Financial Officer		2001		240,000		260,000		—		13,527

Douglas L. Anderson		2003		270,711		240,000		—		7,150
Senior Vice President and		2002		200,000		325,000		—		7,150
General Counsel		2001		154,427		200,000		—		6,630

Keith D. Hartje		2003		180,000		65,000		—		7,796
Senior Vice President and		2002		180,000		65,000		—		7,796
Chief Administrative Officer		2001		180,000		60,000		—		6,630

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

(2)

Consists of 401(k) Plan contributions for 2003 for Messrs. Sokol, Abel, Goodman and Anderson of $7,150, and Mr. Hartje of $7,796. To offset its obligations under the Company's Executive Split Dollar Plan for executives whose retirement benefit cannot be fully funded through the Company's Base Retirement Plan for Salaried Employees, the Company has agreed to pay the premiums for policies of split dollar life insurance on the lives of such executives. No premiums were paid in 2003 for Mr. Sokol, Mr. Abel, or Mr. Goodman. Included are the insurance premiums in the following amounts paid by the Company with respect to the term life insurance portion of premiums paid in 2003 for Mr. Sokol of $810, for Mr. Abel of $540 and for Mr. Goodman of $242.

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 2003 through 2007 and continued employment during such time.

Option Grants in Last Fiscal Year

MEHC did not grant any options during 2003.

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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, 2003.


					Underlying Unexercised Options Held (#)				Value of Unexercised In-the-money Options ($) ⁽¹⁾
Name	Shares Acquired on Exercise (#)		Value Realized		Exercisable		Unexercisable		Exercisable		Unexercisable
David Sokol		—		—		1,399,277		—		N/A		N/A
Gregory E. Abel		—		—		649,052		—		N/A		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 and, consequently, its management does not believe there is a reliable method of computing the fair market value of the stock as of December 31, 2003.

Long-Term Incentive Plans – Awards in Last Fiscal Year

Name

Number of Shares,
Units or Other
Rights (#)

Performance or Other
Period Until Maturation
or Payout

Threshold
($)⁽¹⁾

Target
($)⁽¹⁾

Maximum
($)

Patrick J. Goodman

N/A

December 31, 2007

412,500

N/A

Douglas L. Anderson

N/A

December 31, 2007

390,000

N/A

Keith D. Hartje

N/A

December 31, 2007

163,913

N/A

(1)

The awards shown in the foregoing table are made pursuant to the Long-Term Incentive Partnership Plan ("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 2003) with any unvested balances forfeited upon termination of employment unless the participant retires at or above age 55 with at least 5 years of service in which case the participant will receive any unvested portion of the award. 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 all of the award. Messrs. Sokol and Abel are not participants in the LTIP. 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 $20,000 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.

Retirement Plans

The Company maintains a Supplemental Retirement Plan for Designated Officers, which the Company refers to as the Supplemental Plan, to provide additional retirement benefits to designated participants, as determined by the Board of Directors. Messrs. Sokol, Abel, Goodman and Hartje are participants in the Supplemental Plan. The Supplemental Plan 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

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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 service in order to be eligible to receive benefits under the Supplemental Plan. 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 Supplemental Plan. A participant who elects early retirement is entitled to reduced benefits under the Supplemental Plan, 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 Supplemental Plan. Benefits from the Supplemental Plan 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 Supplemental Plan.

The supplemental retirement benefit will be reduced by the amount of the participant's regular retirement benefit under the MidAmerican Energy Cash Balance Retirement Plan, which the Company refers to as the MidAmerican Retirement Plan, that became effective January 1, 1997 and by benefits under the Iowa Resources Inc. and Subsidiaries Supplemental Retirement Income Plan ("IOR Supplemental Plan"), as applicable.

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.

Part A of the 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 accredited 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.

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The table below shows the estimated aggregate annual benefits payable under the Supplemental Plan 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 Supplemental Plan.


	Estimated Annual Benefit
	Age at Retirement
Total Cash Compensation 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, 2004.

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 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, the immediate vesting of all of his options and the continuation of his senior executive employee benefits (or the economic equivalent thereof) through this 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.

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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, 2004.


Name and Address of Beneficial Owner⁽¹⁾	Number of Shares Beneficially Owned⁽²⁾		Percentage 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 Inc. ⁽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, 29^th 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 Inc. 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.

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,

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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, 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 and three of its consolidated subsidiaries $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.

MEHC did not purchase any options or securities from its stockholders, directors or executive officers during the year ended December 31, 2003.

On January 6, 2004, MEHC purchased shares of common stock from Mr. Sokol for an aggregate 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."

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Item 14. Principal Accountant Fees and Services.

Aggregate fees billed to the Company as a consolidated entity for the fiscal years ending December 31, 2003 and 2002 by the Company's principal accounting firm, Deloitte & Touche LLP and their respective affiliates (collectively, "Deloitte"), 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,
	2003		2002
	(in millions)
Audit Fees ⁽¹⁾	$	2.6	$	2.2
Audit-Related Fees ⁽²⁾		0.3		0.4
Tax Fees ⁽³⁾		0.9		1.3
All Other Fees ⁽⁴⁾		—		—
Total aggregate fees billed	$	3.8	$	3.9

(1)

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

(2)

Includes the aggregate fees billed for each of the last two fiscal years for assurance and related services by Deloitte that are reasonably related to the performance of the audit or review of the registrant'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 for each of the last two fiscal years for professional services rendered by Deloitte for tax compliance, tax advice, and tax planning.

(4)	Includes the aggregate fees billed for each of the last two fiscal years for products and services provided by Deloitte, 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 in and for fiscal 2003 as set forth in the above table and concluded that such services were compatible with maintaining the auditors' independence. Under the Sarbanes-Oxley Act of 2002, all audit and non-audit services performed by the Company's independent accountants must now be approved in advance by the audit committee to assure that such services do not impair the accountants' independence from the Company. Accordingly, the audit committee has adopted 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 independent accountants 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 independent auditors. 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.

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PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K


(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 111.
See Schedule II on page 114.
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.


(iii)	Exhibits

See Item 15 (c) below.


(b)	Reports on Form 8-K

MEHC filed the following Current Reports on Form 8-K during the fourth quarter of 2003:


•	MEHC filed a Current Report on Form 8-K on October 15, 2003.


•	MEHC filed a Current Report on Form 8-K on October 17, 2003.


•	MEHC filed an amended Current Report on Form 8-K on October 21, 2003.


(c)	Exhibits

The exhibits listed on the accompanying Exhibit Index are filed as part of this Annual Report.


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

Not applicable.

110

MidAmerican Energy Holdings Company	Schedule I
Parent Company Only
Condensed Balance Sheets As of December 31, 2003 and 2002 (Amounts in thousands)


	2003			2002
ASSETS
Current assets — Cash and cash equivalents	$	328,750		$	320,629
Investments in and advances to subsidiaries and joint ventures		5,728,125			5,264,786
Equipment, net		15,388			15,984
Goodwill		1,370,241			1,381,009
Deferred charges and other assets		180,331			150,056
Total assets	$	7,622,835		$	7,132,464
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities: Accounts payable and other accrued liabilities	$	49,144		$	94,389
Current portion of long-term debt		—			215,000
Current portion of subordinated debt		100,000			—
Total current liabilities .		149,144			309,389
Non-current liabilities		31,298			11,885
Notes payable — affiliate		86,045			94,795
Senior debt		2,777,878			2,323,387
Subordinated debt		1,772,146			—
Total liabilities		4,816,511			2,739,456
Deferred income		32,916			35,313
Minority interest		1,963			—
Company-obligated mandatorily redeemable preferred securities of subsidiary trusts		—			2,063,412
Stockholders' equity:
Zero coupon convertible preferred stock — authorized 50,000 shares, no par value; 41,263 shares outstanding at December 31, 2003 and 2002		—			—
Common stock — authorized 60,000 shares, no par value; 9,281 shares outstanding at December 31, 2003 and 2002		—			—
Additional paid in capital		1,957,277			1,956,509
Retained earnings		999,627			584,009
Accumulated other comprehensive loss, net		(185,459	)		(246,235	)
Total stockholders' equity		2,771,445			2,294,283
Total liabilities and stockholders' equity	$	7,622,835		$	7,132,464

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

111

MidAmerican Energy Holdings Company	Schedule I
Parent Company Only (continued)
Condensed Statements of Operations For the three years ended December 31, 2003 (Amounts in thousands)


	2003		2002		2001
Revenue:
Equity in undistributed earnings of subsidiary companies and joint ventures	$	785,072	$	477,588	$	608,896
Dividends and distributions from subsidiary companies and joint ventures		318,665		351,847		87,625
Interest and other income		19,808		1,286		2,248
Total revenue		1,123,545		830,721		698,769
Costs and expenses:
General and administration		34,517		29,368		41,078
Depreciation and amortization		710		815		31,537
Interest, net of capitalized interest		251,578		173,240		148,680
Total costs and expenses .		286,805		203,423		221,295
Income before provision for income taxes		836,740		627,298		477,474
Provision for income taxes		250,971		99,588		250,064
Income before minority interest		585,769		527,710		227,410
Minority interest and preferred dividends		170,151		147,667		80,137
Income before and cumulative effect of change in accounting principle		415,618		380,043		147,273
Cumulative effect of change in accounting principle, net of tax		—		—		(4,604	)
Net income available to common stockholders	$	415,618	$	380,043	$	142,669

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

112

MidAmerican Energy Holdings Company	Schedule I
Parent Company Only (continued)
Condensed Statements of Cash Flows For the three years ended December 31, 2003 (Amounts in thousands)


	2003			2002			2001
Cash flows from operating activities	$	(260,271	)	$	(188,300	)	$	(272,906	)
Cash flows from investing activities:
Decrease (increase) in advances to and investments in subsidiaries and joint ventures		205,206			(1,692,742	)		204,118
Other, net		30,995			10,307			(5,297	)
Net cash flows from investing activities		236,201			(1,682,435	)		198,821
Cash flows from financing activities:
Proceeds from issuance of common and preferred stock		—			402,000			—
Proceeds from issuance of trust preferred securities		—			1,273,000			—
Repayment of subordinated debt		(198,958	)		—			—
Proceeds from issuances of senior debt		449,295			700,000			—
Repayments of senior debt		(215,000	)		—			(32	)
Net (repayment of) proceeds from corporate revolving credit facility		—			(153,500	)		68,500
Other		(3,146	)		(32,660	)		(82	)
Net cash flows from financing activities		32,191			2,188,840			68,386
Net change in cash and cash equivalents		8,121			318,105			(5,699	)
Cash and cash equivalents at beginning of year		320,629			2,524			8,223
Cash and cash equivalents at end of year	$	328,750		$	320,629		$	2,524
Supplemental disclosures:
Interest paid, net of interest capitalized	$	219,910		$	164,267		$	148,999
Income taxes paid	$	9,911		$	101,225		$	133,139

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

113

Schedule II

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2002
(Amounts in thousands)


Column A Description	Column B Balance at Beginning of Year		Column C Additions						Column D Deductions			Column E Balance at End of Year
Column A Description	Column B Balance at Beginning of Year		Charged to Income		Other Accounts		Acquisition Reserves⁽²⁾		Column D Deductions			Column E Balance at End of Year
Reserves Deducted From Assets
To Which They Apply:
Reserve for uncollectible accounts receivable:
Year ended 2003	$	39,742	$	13,620	$	—	$	—	$	(27,358	)	$	26,004
Year ended 2002	$	7,319	$	27,782	$	—	$	10,142	$	(5,501	)	$	39,742
Year ended 2001	$	32,685	$	17,061	$	—	$	—	$	(42,427	)	$	7,319
Reserves Not Deducted From Assets ^(1):
Year ended 2003	$	10,981	$	10,527	$	—	$	—	$	(4,091	)	$	17,417
Year ended 2002	$	13,631	$	2,798	$	247	$	—	$	(5,695	)	$	10,981
Year ended 2001	$	25,063	$	5,046	$	—	$	—	$	(16,478	)	$	13,631

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.

114

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 3^rd day of March 2004.

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* __________________________ David L. Sokol Chairman of the Board, Chief Executive Officer, and Director				March 3, 2004
/s/ Gregory E. Abel* __________________________ Gregory E. Abel President, Chief Operating Officer and Director				March 3, 2004
/s/ Patrick J. Goodman* __________________________ Patrick J. Goodman Senior Vice President and Chief Financial Officer				March 3, 2004
/s/ Edgar D. Aronson* __________________________ Edgar D. Aronson Director				March 3, 2004
/s/ Stanley J. Bright* __________________________ Stanley J. Bright Director				March 3, 2004
/s/ Walter Scott, Jr.* __________________________ Walter Scott, Jr. Director				March 3, 2004
/s/ Marc D. Hamburg* __________________________ Marc D. Hamburg Director				March 3, 2004
/s/ Warren E. Buffett* __________________________ Warren E. Buffett Director				March 3, 2004

115


Signature				Date
/s/ John K. Boyer* __________________________ John K. Boyer Director				March 3, 2004
/s/ W. David Scott* __________________________ W. David Scott Director				March 3, 2004
/s/ Richard R. Jaros* __________________________ Richard R. Jaros Director				March 3, 2004
*By: /s/ Douglas L. Anderson ______________________				March 3, 2004
Douglas L. Anderson Attorney-in-Fact

116

EXHIBIT INDEX


Exhibit No.
3.1				Amended and Restated Articles of Incorporation of MEHC effective March 6, 2002 (incorporated by reference to Exhibit 3.3 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
3.2				Bylaws of MEHC (incorporated by reference to Exhibit 3.2 to MEHC'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 MEHC 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 MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.2				First Supplemental Indenture, dated as of October 4, 2002, by and between MEHC 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 MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.3				Registration Rights Agreement, dated as of October 1, 2002, by and between MEHC and Credit Suisse First Boston (as Representative for the Initial Purchasers) (incorporated by reference to Exhibit 4.3 of MEHC'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 MEHC, as issuer, and the Bank of New York, as Trustee (incorporated by reference to Exhibit 10.129 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1995).
4.5				Indenture, dated as of October 15, 1997, among MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MEHC'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 MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to MEHC'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 MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MEHC'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 MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to MEHC's Current Report on Form 8-K dated November 10, 1998).
4.9				Indenture, dated as of March 14, 2000, among MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.9 to MEHC'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 MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).

117


Exhibit No.
4.11				Indenture, dated as of March 12, 2002, between MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.11 to MEHC'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 MEHC'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 MEHC'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 MEHC'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 MEHC'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 MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.17				Indenture, dated as of August 16, 2002, between MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.17 of MEHC'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 MEHC'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 MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.1				Employment Agreement between MEHC and David L. Sokol, dated May 10, 1999 (incorporated by reference to Exhibit 10.1 to MEHC'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 MEHC and David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.2 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.3				Non-Qualified Stock Options Agreements of David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.3 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.4				Amended and Restated Employment Agreement between MEHC and Gregory E. Abel, dated May 10, 1999 (incorporated by reference to Exhibit 10.3 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.5				Non-Qualified Stock Options Agreements of Gregory E. Abel, dated March 14, 2000 (incorporated by reference to Exhibit 10.5 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.6				Employment Agreement between MEHC and Patrick J. Goodman, dated April 21, 1999 (incorporated by reference to Exhibit 10.5 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).

118


Exhibit No.
10.7				MidAmerican Energy Holdings Company, Amended and Restated Long Term Incentive Partnership Plan dated as of January 1, 2003 (incorporated by reference to Exhibit 10.1 of MEHC's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003).
10.8				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.9				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.10				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 MEHC'sAnnual Report on Form 10-K for the year ended December 31, 1993).
10.11				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.12				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.13				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.14				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.15				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.16				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).

119


Exhibit No.
10.17				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.18				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.19				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.20				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.21				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.22				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.23				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 MEHC's Annual Report on Form10-K for the year ended December 31, 1993).
10.24				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 MEHC's 1994 Annual Report on Form 10-K for the year ended December 31, 1993).
10.25				Trust Indenture, dated as of November 27, 1995, between the CE Casecnan Water and Energy Company, Inc. and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996).
10.26				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).

120


Exhibit No.
10.27				Term Loan and Revolving Facility Agreement, dated as of October 28, 1996, among CE Electric UK Holdings, CE Electric UK plc and Credit Suisse (incorporated by reference to Exhibit 10.130 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1995).
10.28				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 MEHC's Annual Report on Form 10-K for the year ended December 31, 1998).
10.29				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).
10.30				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).
10.31				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).
10.32				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).
10.33				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).
10.34				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).
10.35				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).
10.36				Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947 (incorporated by reference to Exhibit 7B filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-6922).
10.37				Sixth Supplemental Indenture, dated as of July 1, 1967 (incorporated by reference to Exhibit 2.08 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-28806).
10.38				Twentieth Supplemental Indenture, dated as of May 1, 1982 (incorporated by reference to Exhibit 4.B.23 to the Iowa-Illinois Gas and Electric Company Quarterly Report on Form 10-Q for the period ended June 30, 1982, Commission File No. 1-3573).

121


Exhibit No.
10.39				Resignation and Appointment of successor Individual Trustee (incorporated by reference to Exhibit 4.B.30 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 33-39211).
10.40				Twenty-Eighth Supplemental Indenture, dated as of May 15, 1992 (incorporated by reference to Exhibit 4.31.B to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated May 21, 1992, Commission File No. 1-3573).
10.41				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 10.41 of MEHC's annual report on Form 10-K for the year ended December 31, 2003).
10.42				Thirtieth Supplemental Indenture, dated as of October 1, 1993 (incorporated by reference to Exhibit 4.34.A to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K, dated October 7, 1993, Commission File No. 1-3573).
10.43				Thirty-First Supplemental Indenture, dated as of July 1, 1995, between Iowa-Illinois Gas and Electric Company and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.16 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended dated December 31, 1995, Commission File No. 1-11505).
10.44				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 of MEHC's annual report on Form 10-K for the year ended December 31, 2003).
10.45				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 of MEHC's annual report on Form 10-K for the year ended December 31, 2003).
10.46				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 of MEHC's annual report on Form 10-K for the year ended December 31, 2003).
10.47				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 of MEHC's annual report on Form 10-K for the year ended December 31, 2003).
10.48				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 of MEHC's annual report on Form 10-K for the year ended December 31, 2003).
10.49				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 of MEHC's annual report on Form 10-K for the year ended December 31, 2003).

122


Exhibit No.
10.50				CalEnergy Company, Inc. Voluntary Deferred Compensation Plan, effective December 1, 1997, First Amendment, dated as of August 17, 1999, and Second Amendment effective March 2000 (incorporated by reference to Exhibit 10.50 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.51				MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan (incorporated by reference to Exhibit 10.51 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.52				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 MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.53				MidAmerican Energy Company Restated Executive Deferred Compensation Plan (incorporated by reference to Exhibit 10.6 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.54				MidAmerican Energy Holdings Company Restated Deferred Compensation Plan-Board of Directors (incorporated by reference to Exhibit 10 to MEHC's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).
10.55				MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated Deferred Compensation Plan-Board of Directors (incorporated by reference to Exhibit 10.63 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.56				Midwest Resources Inc. Supplemental Retirement Plan (formerly the Midwest Energy Company Supplemental Retirement Plan (incorporated by reference to Exhibit 10.10 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654).
10.57				Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement Plan (incorporated by reference to Exhibit 10.24 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
10.58				Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan for Designated Officers, as amended as of July 28, 1994 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-3573).
10.59				Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Designated Officers, as amended as of July 1, 1993 (incorporated by reference to Exhibit 10.K.2 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-3573).
10.60				Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Key Employees, dated as of April 26, 1991 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1991, Commission File No. 1-3573).
10.61				Iowa-Illinois Gas and Electric Company Board of Directors' Compensation Deferral Plan (incorporated by reference to Exhibit 10.K.4 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-3573).

123


Exhibit No.
10.62				Iowa Utilities Board Settlement Agreement among MidAmerican Energy Company, Office of Consumer Advocate, Iowa Energy Consumers, Aluminum Company of America, Deere & Company, Cargill Inc., U.S. Gypsum Company, Interstate Power Company and IES Utilities, Inc. (incorporated by reference to Exhibit 10.16 to the MidAmerican Funding, LLC and MidAmerican Energy Company respective Annual Reports on the combined Form 10-K for the year ended December 31, 2000, Commission File Nos. 333-90553 and 1-11505, respectively).
10.63				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 MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.64				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 MEHC, KR Holding, LLC, KR Acquisition 1, LLC and KR Acquisition 2, LLC (incorporated by reference to Exhibit 99.2 to MEHC's Current Report on Form 8-K dated March 28, 2002).
10.65				MidAmerican Energy Holdings Company Executive Incremental Profit Sharing Plan (incorporated by reference to Exhibit 10.2 of MEHC's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003.)
10.67				Purchase and Sale Agreement, dated as of July 28, 2002, between Dynegy Inc., NNGC Holding Company, Inc. and MEHC (incorporated by reference to Exhibit 99.2 to MEHC's Current Report on Form 8-K dated July 30, 2002).
14.1				MidAmerican Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers (incorporated by reference to Exhibit 14.1 of MEHC's annual report on Form 10-K for the year ended December 31, 2003).
21.1				Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 of MEHC's annual report on Form 10-K for the year ended December 31, 2003).
24.1				Power of Attorney (incorporated by reference to Exhibit 24.1 of MEHC's annual report on Form 10-K for the year ended December 31, 2003).
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.

124

(State or other jurisdiction of
incorporation or organization)

(I.R.S. Employer
Identification No.)

666 Grand Avenue, Des Moines, IA

(Address of principal executive offices)

(Zip Code)