S-4/A 1 file001.htm AMENDMENT NO. 1 TO S-4

As filed with the Securities and Exchange Commission on March 5, 2004

     Registration No. 333-113022

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

AMENDMENT NO. 1
TO
FORM S-4
REGISTRATION STATEMENT UNDER
THE SECURITIES ACT OF 1933

MidAmerican Energy Holdings Company

(Exact name of registrant as specified in its charter)


Iowa 4900 94-2213782
(State or other jurisdiction of
incorporation or organization)		   (Primary Standard Industrial Classification Code Number )    (I.R.S. Employer Identification Number ) 

666 Grand Avenue
Des Moines, Iowa 50309
(515) 242-4300
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Douglas L. Anderson
General Counsel
MidAmerican Energy Holdings Company
302 South 36th Street
Suite 400
Omaha, Nebraska 68131
(402) 341-4500
(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copy to:
Peter J. Hanlon, Esq.
Willkie Farr & Gallagher LLP
787 Seventh Avenue
New York, New York 10019
(212) 728-8000

Approximate date of commencement of proposed sale to the public: As soon as practicable following the effective date of this Registration Statement.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. [ ]

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ]

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ]

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.



The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, Dated March 5, 2004

Prospectus

Offer to Exchange

Up to $250,000,000 in aggregate principal amount of registered 5.00% Senior Notes due 2014 for

All outstanding unregistered 5.00% Senior Notes due 2014

•  We are offering to exchange new registered 5.00% senior notes due 2014 for all of our outstanding unregistered 5.00% senior notes due 2014.
•  The exchange offer expires at 5:00 p.m., New York City time, on April 2, 2004, unless extended.
•  The exchange offer is subject to customary conditions that may be waived by us.
•  All original notes outstanding that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer will be exchanged for the exchange notes.
•  Tenders of original notes may be withdrawn at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.
•  The exchange of original notes for exchange notes will not be a taxable exchange for U.S. federal income tax purposes.
•  We will not receive any proceeds from the exchange offer.
•  The terms of the exchange notes to be issued are substantially identical to the terms of the original notes, except that the exchange notes will not have transfer restrictions, and you will not have registration rights.
•  There is no established trading market for the exchange notes, and we do not intend to apply for listing of the exchange notes on any securities exchange or market quotation system.

See "Risk Factors" beginning on page 8 for a discussion of matters you should consider before you participate in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this Prospectus is                             , 2004



TABLE OF CONTENTS


  Page
SUMMARY   1  
RISK FACTORS   8  
FORWARD-LOOKING STATEMENTS   18  
USE OF PROCEEDS   19  
THE EXCHANGE OFFER   20  
SELECTED CONSOLIDATED FINANCIAL
 AND OPERATING DATA		   29  
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   31  
QUANTITATIVE AND QUALITATIVE
DISCLOSURE ABOUT MARKET RISK		   47  
BUSINESS   49  
REGULATION   69  
LEGAL PROCEEDINGS   82  
MANAGEMENT   85  
DESCRIPTION OF THE NOTES   93  
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS   109  
PLAN OF DISTRIBUTION   110  
NOTICE TO CANADIAN RESIDENTS   111  
LEGAL MATTERS   111  
EXPERTS   111  
WHERE YOU CAN FIND MORE INFORMATION   111  
FINANCIAL STATEMENTS   F-1  

In this prospectus, references to "we," "our" and "us" are to MidAmerican Energy Holdings Company and, except as the context otherwise requires, its consolidated subsidiaries and, as applicable, its equity investments.

In this prospectus, references to "U.S. dollars," "dollars," "US $," "$" 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.

This prospectus incorporates important business and financial information about us that is not included or delivered with this prospectus. We will provide this information to you at no charge upon written or oral request directed to Douglas L. Anderson, General Counsel, MidAmerican Energy Holdings Company, 302 South 36th Street, Suite 400, Omaha, Nebraska 68131, (402) 341-4500. In order to ensure timely delivery of the information, any request should be made by March 25, 2004.

No dealer, salesperson or other individual has been authorized to give any information or to make any representations not contained in this prospectus in connection with the exchange offer. If given or made, such information or representations must not be relied upon as having been authorized by us. Neither the delivery of this prospectus nor any sale made hereunder shall, under any circumstances, create any implications that there has not been any change in the facts set forth in this prospectus or in our affairs since the date hereof.

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. The letter of transmittal accompanying this prospectus states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act of 1933, as amended. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of the exchange notes received in exchange for original notes where such original notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 120 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resales. See "Plan of Distribution."

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NOTICE TO NEW HAMPSHIRE RESIDENTS

NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER, OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.

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SUMMARY

This section contains a general summary of certain of the information contained in this prospectus. It may not include all of the information that is important to you. You should read this entire prospectus, including the "Risk Factors" section and the financial statements and notes to those statements, before making an investment decision.

MIDAMERICAN ENERGY HOLDINGS COMPANY

Overview

We are a United States-based global energy company. Our operations are organized and managed on seven distinct platforms which we refer to as: MidAmerican Energy, Northern Natural Gas, Kern River, CE Electric UK (which includes Northern Electric and Yorkshire), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and HomeServices. Through these seven platforms, we own and operate 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 electric power projects and the second largest residential real estate brokerage firm in the United States. The following is a chart of our operating platforms and the principal lines of business in which they are engaged:

Our principal energy subsidiaries generate, transmit, store, distribute and supply energy. Our electric and natural gas utility subsidiaries currently serve approximately 4.4 million electricity customers and approximately 670,000 natural gas customers. Our 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. We have 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 our 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.

We are a privately owned company with publicly held fixed income securities. Since March 14, 2000, our sole shareholders have consisted of a private investor group comprised of Berkshire Hathaway Inc., or Berkshire Hathaway, Walter Scott, Jr. and members of his family, David L. Sokol, our Chairman and Chief Executive Officer, and Gregory E. Abel, our President and Chief Operating Officer. Prior to that time, our common stock was publicly traded on the New York Stock Exchange.

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

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THE EXCHANGE OFFER

On February 12, 2004, we privately placed $250,000,000 aggregate principal amount of 5.00% senior notes due 2014, which we refer to as the original series D notes, in a transaction exempt from registration under the Securities Act of 1933, as amended, or the Securities Act. In connection with the private placement, we entered into a registration rights agreement, dated as of February 9, 2004, with the initial purchasers of the original series D notes. In the registration rights agreement, we agreed to offer our new 5.00% senior notes due 2014, which will be registered under the Securities Act, and which we refer to as the series D exchange notes, in exchange for the original series D notes. The exchange offer is intended to satisfy our obligations under the registration rights agreement. We also agreed to deliver this prospectus to the holders of the original series D notes. In this prospectus, we refer to the original series D notes and the series D exchange notes collectively as the series D notes. You should read the discussion under the headings "Summary — Terms of the Series D Notes" and "Description of Notes" for information regarding the series D notes.

The Exchange Offer This is an offer to exchange $1,000 in principal amount of series D exchange notes for each $1,000 in principal amount of original series D notes. The series D exchange notes are substantially identical to the original series D notes, except that the series D exchange notes will generally be freely transferable. We believe that you can transfer the series D exchange notes without complying with the registration and prospectus delivery provisions of the Securities Act if you:
• acquire the series D exchange notes in the ordinary course of your business;
• are not and do not intend to become engaged in a distribution of the series D exchange notes;
• are not an "affiliate" (within the meaning of the Securities Act) of ours;
• are not a broker-dealer (within the meaning of the Securities Act) that acquired the original series D notes from us or our affiliates; and
• are not a broker-dealer (within the meaning of the Securities Act) that acquired the original series D notes in a transaction as part of its market-making or other trading activities.
If any of these conditions are not satisfied and you transfer any series D exchange note without delivering a proper prospectus or without qualifying for a registration exemption, you may incur liability under the Securities Act. See "The Exchange Offer — Terms of the Exchange."
Registration Rights Agreement Under the registration rights agreement, we have agreed to use our reasonable best efforts to consummate the exchange offer or cause the original series D notes to be registered under the Securities Act to permit resales. If we are not in compliance with our obligations under the registration rights agreement, liquidated damages will accrue on the original series D notes in addition to the

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interest that is otherwise due on the original series D notes. If the exchange offer is completed on the terms and within the time period contemplated by this prospectus, no liquidated damages will be payable on the original series D notes. The series D exchange notes will not contain any provisions regarding the payment of liquidated damages. See "The Exchange Offer — Liquidated Damages."
Minimum Condition The exchange offer is not conditioned on any minimum aggregate principal amount of original series D notes being tendered for exchange.
Expiration Date The exchange offer will expire at 5:00 p.m., New York City time, on April 2, 2004, unless we extend it.
Exchange Date Original series D notes will be accepted for exchange at the time when all conditions of the exchange offer are satisfied or waived. The series D exchange notes will be delivered promptly after we accept the original series D notes.
Conditions to the Exchange Offer Our obligation to complete the exchange offer is subject to certain conditions. See "The Exchange Offer — Conditions to the Exchange Offer." We reserve the right to terminate or amend the exchange offer at any time prior to the expiration date upon the occurrence of certain specified events.
Withdrawal Rights You may withdraw the tender of your original series D notes at any time before the expiration of the exchange offer on the expiration date. Any original series D notes not accepted for any reason will be returned to you without expense as promptly as practicable after the expiration or termination of the exchange offer.
Procedures for Tendering Original
    Notes		 See "The Exchange Offer — How to Tender."
United States Federal Income Tax     Consequences The exchange of the original series D notes for series D exchange notes will not be a taxable exchange for U.S. federal income tax purposes, and holders will not recognize any taxable gain or loss as a result of such exchange.
Effect on Holders of Original Notes If the exchange offer is completed on the terms and within the period contemplated by this prospectus, holders of original series D notes will have no further registration or other rights under the registration rights agreement, except under limited circumstances. See "The Exchange Offer — Other."

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Holders of original series D notes who do not tender their original series D notes will continue to hold those original series D notes. All untendered, and tendered but unaccepted, original series D notes will continue to be subject to the transfer restrictions provided for in the original series D notes and the indenture under which the original series D notes have been issued. To the extent that original series D notes are tendered and accepted in the exchange offer, the trading market, if any, for the original series D notes could be adversely affected. See "Risk Factors — Risks Associated with the Exchange Offer — You may not be able to sell your original series D notes if you do not exchange them for registered series D exchange notes in the exchange offer."; " — Your ability to sell your original series D notes may be significantly more limited and the price at which you may be able to sell your original series D notes may be significantly lower if you do not exchange them for registered series D exchange notes in the exchange offer."; and "The Exchange Offer — Other."
Use of Proceeds We will not receive any proceeds from the issuance of series D exchange notes in the exchange offer.
Exchange Agent The Bank of New York is serving as the exchange agent in connection with the exchange offer.

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TERMS OF THE SERIES D NOTES

General $250,000,000 aggregate principal amount of 5.00% Senior Notes due February 15, 2014. The original series D notes were, and the series D exchange notes will be, issued under a supplemental indenture, dated as of February 12, 2004, to the indenture, dated as of October 4, 2002 and amended as of May 16, 2003, between us and The Bank of New York, as trustee. On October 4, 2002, we issued $200,000,000 of our 4.625% Senior Notes due 2007 (hereafter referred to as the series A notes) and $500,000,000 of our 5.875% Senior Notes due 2012 (hereafter referred to as the series B notes), and on May 16, 2003, we issued $450,000,000 of our 3.50% Senior Notes due 2008 (hereafter referred to as the series C notes), in each case pursuant to the indenture. Unless otherwise indicated, references hereafter to the notes in this prospectus include the series A notes, the series B notes, the series C notes and the series D notes (and any other series of notes or other securities hereafter issued under a supplemental indenture or otherwise pursuant to the indenture).
Interest Payment Dates February 15 and August 15 of each year, commencing August 15, 2004.
Optional Redemption We may redeem the series D notes, at our option, in whole or in part, at any time, at a redemption price equal to the greater of:
(1) 100% of the principal amount of the series D notes to be redeemed; or
(2) the sum of the present values of the remaining scheduled payments of principal of and interest on the series D notes to be redeemed discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at a discount rate equal to the yield on equivalent Treasury securities plus 20 basis points,
plus, for (1) or (2) above, whichever is applicable, accrued and unpaid interest, if any, on such series D notes to the date of redemption.
Sinking Fund The series D notes are not subject to a mandatory sinking fund.
Change of Control Upon the occurrence of a Change of Control, each holder of the notes will have the right, at the holder's option, to require us to repurchase all or any part of the holder's notes at a purchase price in cash equal to 101% of the principal thereof, plus accrued and unpaid interest, if any,

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to the date of such purchase in accordance with the procedures set forth in the indenture for the notes. A Change of Control means the occurrence of both of the following: (1) a transaction pursuant to which Berkshire Hathaway ceases to own, on a diluted basis, at least a majority of our common stock, assuming conversion of all convertible securities then owned by Berkshire Hathaway, without regard to whether then presently convertible, or we or our subsidiaries dispose of all or substantially all of our property and that of our subsidiaries to any entity which is not so majority owned by Berkshire Hathaway, and (2) within 90 days after the earlier of the announcement or occurrence of any such transaction, a downgrade in the ratings for the notes (generally to below investment grade by both Moody's Investors Service, Inc., or Moody's, and Standard & Poor's Rating Service, or S&P) occurs. See "Description of the Notes — Covenants — Purchase of Notes Upon a Change of Control."
Ranking The series D notes are our general, unsecured senior obligations and will rank pari passu in right of payment with all our other existing and future senior unsecured obligations (including the series A notes, series B notes and series C notes) and senior in right of payment to all our existing and future subordinated obligations. The series D notes are effectively subordinated to all our existing and future secured obligations and to all existing and future obligations of our subsidiaries.
Covenants The indenture contains covenants that, among other things, restrict our ability to grant liens on our assets and our ability to merge, consolidate or transfer or lease all or substantially all of our consolidated assets. See "Description of the Notes — Covenants."
Events of Default Events of default with respect to the notes of any series under the indenture include, among other things:
(1) default in the payment of any interest on any notes of that series for 30 days after payment is due;
(2) default in the payment of principal of, or premium, if any, on any note of that series or as to any payment required in connection with a Change of Control as described above;
(3) our failure to perform, or breach by us of, any covenant contained in the indenture or the notes of that series, which failure continues for 30 days after written notice thereof is provided to us pursuant to the indenture;
(4) our failure or the failure of any of our significant subsidiaries (as defined later in this prospectus) to pay

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when due beyond any applicable grace period, or the acceleration of, debt (other than debt that is non-recourse to us) in excess of $100,000,000;
(5) the entry by a court of one or more judgments against us or any of our significant subsidiaries (other than a judgment that is non-recourse to us) requiring payment by us in an aggregate amount in excess of $100,000,000 which has not been vacated, discharged, satisfied or stayed pending appeal within 60 days from entry; and
(6) the occurrence of certain events of bankruptcy, insolvency or reorganization with respect to us or any of our significant subsidiaries.
See "Description of the Notes — Definitions" and "— Events of Default."
Ratings The series D notes have initially been assigned ratings of Baa3 by Moody's, BBB– by S&P and BBB by Fitch, Inc. However, these ratings are subject to change at any time.
Denomination and Form The original series D notes were, and the series D exchange notes will be, issued in denominations of $1,000 and any integral multiple of $1,000. The original series D notes were, and the series D exchange notes will be, represented by one or more global securities registered in the name of The Depository Trust Company, or DTC, or its nominee. Beneficial interests in the global securities representing the original series D notes are, and beneficial interests in the global securities representing the series D exchange notes will be, shown on, and transfers of the beneficial interests in the global securities representing the original series D notes are, and transfers of the beneficial interests in the global securities representing the series D exchange notes will be, effected only through, records maintained by DTC and its participants. Except as described later in this prospectus, series D notes in certificated form will not be issued. See "Description of the Notes — Global Notes; Book-Entry System."
Trustee The Bank of New York is the trustee for the holders of the series D notes.
Governing Law The series D notes, the indenture and the other documents for the offering of the series D notes are governed by the laws of the State of New York.

Risk Factors

This investment involves risks. Before you invest in the series D notes, you should carefully consider the matters set forth under the heading "Risk Factors" and all other information in this prospectus.

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RISK FACTORS

An investment in the series D notes is subject to numerous risks, including, but not limited to, those set forth below. In addition to the information contained elsewhere in this prospectus, you should carefully consider the following risk factors when evaluating an investment in the series D notes.

Risk Associated with Our Corporate and Financial Structure

We are a holding company that depends on distributions from our subsidiaries and joint ventures to meet our needs.

We are a holding company and derive substantially all of our income and cash flow from our subsidiaries and joint ventures. We expect that future development and acquisition efforts will be similarly structured to involve operating subsidiaries and joint ventures. We are dependent on the earnings and cash flows of, and dividends, loans, advances or other distributions from, our subsidiaries and joint ventures to generate the funds necessary to meet our obligations, including the payment of principal of, or interest and premium, if any, on, the notes. All required payments on debt and preferred stock at subsidiary levels will be made before funds from our subsidiaries are available to us. The availability of distributions from such entities is also subject to:

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

Our subsidiaries and joint ventures are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due pursuant to the notes or to make any funds available, whether by dividends, loans or other payments, for payment of the notes, and do not guarantee the payment of interest or premium, if any, on or principal of the notes.

We are substantially leveraged, the terms of the notes do not restrict our ability or our subsidiaries' ability to incur additional indebtedness that could have an adverse impact on our financial condition and the notes will be structurally subordinated to the indebtedness of our subsidiaries.

Our substantial leverage level presents the risk that we might not generate sufficient cash to service our indebtedness, including the notes, or that our leveraged capital structure could limit our ability to finance future acquisitions, develop additional projects, compete effectively and operate successfully under adverse economic conditions. At December 31, 2003, our outstanding senior indebtedness was approximately $2.8 billion and our outstanding subordinated indebtedness was approximately $1.9 billion. These amounts exclude our guarantee of Salton Sea Funding Corporation's 7.475% Senior Secured Series F Bonds due November 30, 2018 (which we refer to as the Salton Sea Series F Bonds) in an aggregate principal amount of approximately $136.4 million, together with accrued but unpaid interest thereon (which we refer to as our Salton Sea Guarantee), which was effectively terminated on March 1, 2004 through the use of a portion of the proceeds from the offering of the original series D notes. These amounts further exclude our other guarantees and letters of credit in respect of subsidiary and equity investment indebtedness aggregating approximately $124.1 million as of December 31, 2003. Our subsidiaries also have significant amounts of indebtedness. At December 31, 2003, our consolidated subsidiaries had outstanding indebtedness totaling approximately $7.2 billion (which includes the $136.4 million aggregate principal amount of Salton Sea Series F Bonds redeemed on March 1, 2004 through the use of a portion of the proceeds from the offering of the original series D notes). This amount does not include (i) any trade debt or preferred stock obligations of our subsidiaries, (ii) our subsidiaries' letters of credit in respect of their indebtedness, or (iii) our share of the outstanding indebtedness of our and our subsidiaries' equity investments.

The terms of the notes do not limit our ability or the ability of our subsidiaries or joint ventures to incur additional debt or issue additional preferred stock. Accordingly, we or our subsidiaries or

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joint ventures could enter into acquisitions, refinancings, recapitalizations or other highly leveraged transactions that could significantly increase our or their total amount of outstanding debt. The interest payments needed to service this increased level of indebtedness could have a material adverse effect on our or our subsidiaries' operating results. A highly leveraged capital structure could also impair our or our subsidiaries' overall credit quality, making it more difficult for us to finance our operations or issue future indebtedness on favorable terms, and could result in a downgrade in the ratings of our indebtedness, including the series D notes, by credit rating agencies. Further, if any of our or our subsidiaries' indebtedness is accelerated due to an event of default under such indebtedness and such acceleration results in an event of default under some or all of our other indebtedness or the indenture for the notes, we may not have sufficient funds to repay all of the accelerated indebtedness and the notes simultaneously.

Claims of creditors of our subsidiaries and joint ventures will have priority over your claims with respect to the assets and earnings of our subsidiaries and joint ventures. In addition, the stock or assets of substantially all of our operating subsidiaries and joint ventures is directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of the notes.

Risks Associated with Our Business

Our recent growth has been achieved, in part, through strategic acquisitions, and additional acquisitions may not be successful.

Because our industry is rapidly changing, there are opportunities for acquisitions of assets and businesses, as well as for business combinations. We investigate opportunities that may increase shareholder value and build on existing businesses. We have participated in the past and our security holders may assume that at any time we may be participating in bidding or other negotiations for such transactions. This participation may or may not result in a transaction for us. Any transaction that does take place may involve consideration in the form of cash, debt or equity securities.

Since 1996, we have completed several significant acquisitions, including the acquisitions of Northern Electric, Yorkshire, MidAmerican Energy, Kern River and Northern Natural Gas. We intend to continue to actively pursue acquisitions to complement and diversify our existing business for the foreseeable future.

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

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

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

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

Through our operating subsidiaries, we are continuing to develop, construct, own and operate new or expanded facilities, including the project to recover zinc from the geothermal brine utilized at the Imperial Valley site in California, a proposed new geothermal electric generating facility at the Imperial Valley site in California, a proposed new 745-mile (approximate) pipeline to facilitate the transportation of stranded Alaskan natural gas, and new electric generating projects in Iowa, and in the future we expect to pursue the development, construction, ownership and operation of additional new or expanded energy projects (including, without limitation, generation, distribution, transmission, exploration/production, storage and supply projects and related activities, infrastructure and services), both domestically and internationally, the completion of any of which, including any future projects, is subject to substantial risk and may expose us to significant costs. We cannot assure you that our development or construction efforts on any particular project, or our efforts generally, will be successful.

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

Our subsidiaries are subject to certain operating uncertainties which may adversely affect our financial position, results of operation and ability to service the notes.

The operation of complex electric and gas utility (including transmission and distribution systems), pipeline or power generating facilities involves many risks associated with operating uncertainties and events beyond our control. These risks include the breakdown or failure of power generation equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, fuel interruption, performance below expected levels of output, capacity or efficiency, operator error and catastrophic events such as severe storms, fires, earthquakes or explosions. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. The realization of any of these risks could significantly reduce or eliminate our affiliates' revenues or significantly increase our affiliates' expenses, thereby adversely affecting the ability to receive distributions from subsidiaries and joint ventures. For example, if our affiliates cannot operate their electric or natural gas facilities at full capacity due to restrictions imposed by environmental regulations, their revenues could decrease due to decreased wholesale sales and their expenses could increase due to the need to obtain energy from higher cost sources. Any reduction of revenues for such reason, or any other reduction of our affiliates' revenues or increase in their expenses resulting from the risks described above, could decrease our net cash flow and provide us with less funds with which to service the notes.

Further, we cannot assure you that our current and future insurance coverage will be sufficient to replace lost revenue or cover repair and replacement costs, especially in light of the changes in the insurance markets following the September 11, 2001 terrorist attacks that make it more difficult or costly to obtain certain types of insurance.

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

Since the September 11, 2001 terrorist attacks, the United States government has issued warnings that energy assets, specifically our nation's pipeline and electric utility infrastructure, may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Damage to the assets of our fuel suppliers, the assets of our customers or our own assets or at regional transmission facilities inflicted by terrorist groups or saboteurs could result in a

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significant decrease in revenues and significant repair costs, force us to increase security measures, cause changes in the insurance markets and cause disruptions of fuel supplies, energy consumption and markets, particularly with respect to natural gas and electric energy. Any of these consequences of acts of terrorism could materially affect our results of operations and decrease the amount of funds we have available to make payments on the notes. Instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability to raise capital.

We are subject to comprehensive energy regulation and changes in regulation and rates may adversely affect our business, financial condition, results of operations and ability to service the notes.

We are subject to comprehensive governmental regulation, including regulation in the United States by various federal, state and local regulatory agencies, regulation in the United Kingdom and regulation in the Philippines, all of which significantly influences our operating environment, our rates, our capital structure, our costs and our ability to recover our costs from customers. These regulatory agencies include, among others, the Federal Energy Regulatory Commission, or the FERC, the Environmental Protection Agency, or the EPA, the Nuclear Regulatory Commission, or the NRC, the United States Department of Transportation, or the DOT, the Iowa Utilities Board, or the IUB, the Illinois Commerce Commission, other state utility boards, numerous local agencies, the Gas and Electricity Markets Authority, or GEMA, which in discharging certain of its powers acts through its staff within the Office of Gas and Electricity Markets, or Ofgem, in the United Kingdom, and various other governmental agencies in the United States, the United Kingdom and the Philippines. We are currently exempt from the requirement to register with the Securities and Exchange Commission, or SEC, under the Public Utility Holding Company Act of 1935, as amended, or PUHCA, but if we were to cease to be exempt or if we were to become a subsidiary of a non-exempt holding company, we would become subject to additional regulation by the SEC under PUHCA. Under PUHCA, registered holding companies and their subsidiaries are subject to regulation and restrictions with respect to certain of their activities, including securities issuances, acquisitions, investments and affiliate transactions. We are unable to predict the impact on our operating results of the actions or policies of any of these agencies or the SEC under PUHCA. Changes in regulations or the imposition of additional regulations by any of these entities could have a material adverse impact on our results of operations. For example, such changes could result in increased retail competition in MidAmerican Energy's service territory, the acquisition by a municipality (by negotiation or condemnation) of our distribution facilities or a negative impact on our current transportation and cost recovery arrangements.

The structure of federal and state energy regulation is currently undergoing change and has in the past, and may in the future, be the subject of various challenges, initiatives and restructuring proposals by policy makers, utilities and other industry participants. Following the cascading blackouts that occurred in parts of the Midwest and Northeast United States and Eastern Canada on August 14, 2003, federal, state and Canadian officials, as well as non-governmental organizations charged with electric reliability responsibilities, are considering measures designed to ensure the reliability of electric transmission and distribution systems. The implementation of regulatory changes in response to such challenges, initiatives and restructuring proposals could result in the imposition of more comprehensive or stringent requirements on us or our subsidiaries or other industry participants, which would result in increased compliance costs and could have a material adverse effect on our business, financial condition, results of operations and ability to service the notes.

We are subject to environmental, health, safety and other laws and regulations which may adversely impact us.

Through our subsidiaries and joint ventures, we are subject to a number of environmental, health, safety and other laws and regulations affecting many aspects of our present and future operations, both domestic and foreign, including air emissions, water quality, wastewater discharges, solid wastes, hazardous substances and safety matters. We may incur substantial costs and liabilities in connection with our operations as a result of these regulations. In particular, the cost of future compliance with federal, state and local clean air laws, such as those that require certain generators, including some of our subsidiaries' electric generating facilities, to limit nitrogen oxide emissions, mercury emissions and

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other potential pollutants, may require us to make significant capital expenditures which may not be recoverable through future rates. In addition, these costs and liabilities may include those relating to claims for damages to property and persons resulting from our operations. The implementation of regulatory changes imposing more comprehensive or stringent requirements on us, to the extent such changes would result in increased compliance costs or additional operating restrictions, could have a material adverse effect on our business, financial condition, results of operations and ability to service the notes.

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

The Pipeline Safety Improvement Act and the new rule that became effective under that Act on February 14, 2004, together with other potential pipeline safety legislation and an increase in public expectations on pipeline safety, may also require replacement of some of our pipeline segments, addition of monitoring equipment, and more frequent inspection or testing of our pipeline facilities. These requirements coupled with increases in state and federal agency oversight, if adopted, would necessitate additional testing and reporting which may result in higher operating costs and capital costs. Our FERC-approved tariffs or competition from other natural gas sources may not allow us to recover these increased costs of compliance.

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

One of our wholly owned subsidiaries, MidAmerican Energy, is subject to the unique risks associated with nuclear generation.

The risks of nuclear generation include the following:

•  the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
•  limitations on the amounts and types of insurance commercially available to cover 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 NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at nuclear plants, including the facility in which we have an ownership interest, and additional expenditures could be required in the future. In addition, although we have no reason to anticipate a serious nuclear incident at the

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facility in which we have an interest, if an incident did occur, it could have a material but presently undeterminable adverse effect on our financial position, results of operations and ability to service the series D notes.

Increased competition resulting from legislative, regulatory and restructuring efforts could have a significant financial impact on us and our utility subsidiaries and consequently decrease our revenue.

In recent years, some state legislative and regulatory authorities have implemented measures to establish a competitive energy market. The move towards a competitive environment could result in the emergence of numerous strong and capable competitors, many of which may have more extensive operating experience and greater financial resources than we and our subsidiaries. Retail competition and the unbundling of regulated energy and gas service could have a significant adverse financial impact on us and our subsidiaries due to an impairment of assets, a loss of customers, lower profit margins and increased costs of capital. The total impacts of restructuring may have a significant effect on our financial position, results of operations and cash flows. We cannot predict if and when we will be subject to changes in legislation or regulation, nor can we predict the impacts of these changes on our financial position, results of operations or cash flows.

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

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

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

A sustained decrease in demand for natural gas in the markets served by our subsidiaries' pipeline and distribution systems would significantly reduce our revenues. Factors that could lead to a decrease in market demand include:

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

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•  a shift by our pipeline and distribution customers to the use of alternate fuels, such as fuel oil, due to price differentials or other incentives.

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

Our subsidiary, HomeServices of America, Inc., or HomeServices, has experienced strong revenue growth and increases in net income in each of the years ended December 31, 2003 and 2002. The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions which are beyond HomeServices' control. Any of the following could have a material adverse effect on HomeServices' businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect revenues and profitability:

•  rising interest rates or unemployment rates;
•  periods of economic slowdown or recession;
•  decreasing home ownership rates; and
•  declining demand for real estate.

Failure of our significant power purchasers, pipeline customers and United Kingdom retail suppliers to pay amounts due under their contracts could reduce our revenues materially.

Our subsidiaries' non-utility generating facilities and both of our pipeline subsidiaries are dependent upon a relatively small number of customers for a significant portion of their revenues. In addition, our United Kingdom utility distribution businesses are dependent upon a relatively small number of retail suppliers, including one retail supplier who represents approximately 50% of the total revenues of our United Kingdom utility distribution businesses. As a result, our profitability and ability to make payments under the notes generally will depend in part upon the continued financial performance and creditworthiness of these customers. Accordingly, failure of one or more of our most significant customers to pay for contracted electric generating capacity, pipeline capacity reservation charges or distribution system use charges, as applicable, for reasons related to financial distress or otherwise, could reduce our revenues materially if we were not able to make adequate alternate arrangements on a timely basis, such as adequate replacement contracts. The replacement of any of our existing long-term contracts or United Kingdom retail suppliers, should it become necessary, will depend on a number of factors beyond our control, including:

•  the availability of economically deliverable natural gas for transport through our pipeline system, including in particular continued availability of adequate supplies from the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian supply basins currently accessible to our pipeline subsidiaries;
•  existing competition to deliver natural gas to the upper Midwest and southern California;
•  new pipelines or expansions potentially serving the same markets as our pipelines;
•  the growth in demand for natural gas in the upper Midwest, southern California, Nevada and Utah;
•  whether transportation of natural gas pursuant to long-term contracts continues to be market practice;
•  the actions of regulators, including the United Kingdom electricity regulator;
•  the availability and financial condition of replacement United Kingdom retail suppliers;
•  whether our business strategy, including our expansion strategy, continues to be successful.

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

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Our utility and non-utility energy businesses are subject to power and fuel price fluctuations and other commodity price risks and credit risks that could adversely affect our results of operations.

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

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

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

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

We face exchange rate risk.

Payments from some of our foreign investments, including without limitation Northern Electric and Yorkshire, are made in a foreign currency and any dividends or distributions of earnings in respect of such investments may be significantly affected by fluctuations in the exchange rate between

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the United States dollar and the British pound or other applicable foreign currency. Although we may enter into certain transactions to hedge risks associated with exchange rate fluctuations, there can be no assurance that such transactions will be successful in reducing such risks.

Risks Associated with the Exchange Offer

You may not be able to sell your original series D notes if you do not exchange them for registered series D exchange notes in the exchange offer.

If you do not exchange your original series D notes for series D exchange notes in the exchange offer, your original series D notes will continue to be subject to the restrictions on transfer as stated in the legends on the original series D notes. In general, you may not offer, sell or otherwise transfer the original series D notes in the United States unless they are:

•  registered under the Securities Act;
•  offered or sold under an exemption from the Securities Act and applicable state securities laws; or
•  offered or sold in a transaction not subject to the Securities Act and applicable state securities laws.

We do not currently anticipate that we will register the original series D notes under the Securities Act. Except for limited instances involving the initial purchasers or holders of original series D notes who are not eligible to participate in the exchange offer or who receive freely transferable series D exchange notes in the exchange offer, we will not be under any obligation to register the original series D notes under the Securities Act under the registration rights agreement or otherwise. Also, if the exchange offer is completed on the terms and within the time period contemplated by this prospectus, no liquidated damages will be payable on your original series D notes.

Your ability to sell your original series D notes may be significantly more limited and the price at which you may be able to sell your original series D notes may be significantly lower if you do not exchange them for registered series D exchange notes in the exchange offer.

To the extent that original series D notes are exchanged in the exchange offer, the trading market for the original series D notes that remain outstanding may be significantly more limited. As a result, the liquidity of the original series D notes not tendered for exchange could be adversely affected. The extent of the market for original series D notes will depend upon a number of factors, including the number of holders of original series D notes remaining outstanding and the interest of securities firms in maintaining a market in the original series D notes. An issue of securities with a lesser outstanding market value available for trading, which is called the "float," may command a lower price than would be comparable to an issue of securities with a greater float. As a result, the market price for original series D notes that are not exchanged in the exchange offer may be affected adversely to the extent that original series D notes exchanged in the exchange offer reduce the float. The reduced float also may make the trading price of the original series D notes that are not exchanged more volatile.

There are state securities law restrictions on the resale of the series D exchange notes.

In order to comply with the securities laws of certain jurisdictions, the series D exchange notes may not be offered or resold by any holder unless they have been registered or qualified for sale in such jurisdictions or an exemption from registration or qualification is available and the requirements of such exemption have been satisfied. We do not currently intend to register or qualify the resale of the series D exchange notes in any such jurisdictions. However, an exemption is generally available for sales to registered broker-dealers and certain institutional buyers. Other exemptions under applicable state securities laws may also be available.

We will not accept your original series D notes for exchange if you fail to follow the exchange offer procedures and, as a result, your original series D notes will continue to be subject to existing transfer restrictions and you may not be able to sell your original series D notes.

We will issue series D exchange notes as part of the exchange offer only after a timely receipt of your original series D notes, a properly completed and duly executed letter of transmittal and all

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other required documents. Therefore, if you want to tender your original series D notes, please allow sufficient time to ensure timely delivery. If we do not receive your original series D notes, letter of transmittal and other required documents by the expiration date of the exchange offer, we will not accept your original series D notes for exchange. We are under no duty to give notification of defects or irregularities with respect to the tenders of original series D notes for exchange. If there are defects or irregularities with respect to your tender of original series D notes, we will not accept your original series D notes for exchange. See "The Exchange Offer."

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FORWARD-LOOKING STATEMENTS

This prospectus 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 our intentions, plans, expectations and beliefs and are subject to risks, uncertainties and other factors. Many of these factors are outside our control and could cause actual results to differ materially from such forward-looking statements. These factors include, among others:

•  general economic, political and business conditions in the jurisdictions in which our facilities are located;
•  the financial condition and creditworthiness of our significant customers and suppliers;
•  governmental, statutory, regulatory or administrative initiatives or ratemaking actions affecting us or the electric or gas utility, pipeline or power generation industries;
•  weather effects on sales and revenues;
•  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, the SEC, the FERC and similar entities with regulatory oversight;
•  other risks or unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events; and
•  other business or investment considerations that may be disclosed from time to time in our SEC filings or in other publicly disseminated written documents.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exclusive.

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USE OF PROCEEDS

We will not receive any proceeds from the issuance of the series D exchange notes in the exchange offer. The series D exchange notes will evidence the same debt as the original series D notes tendered in exchange for series D exchange notes. Accordingly, the issuance of the series D exchange notes will not result in any change in our indebtedness.

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THE EXCHANGE OFFER

Purpose of the Exchange Offer

On February 12, 2004, we privately placed the original series D notes in a transaction exempt from registration under the Securities Act. Accordingly, the original series D notes may not be reoffered, resold or otherwise transferred in the United States unless so registered or unless an exemption from the Securities Act registration requirements is available. Pursuant to a registration rights agreement with the initial purchasers of the original series D notes, we agreed, for the benefit of holders of the series D notes, to:

•  prepare and file an exchange offer registration statement with the SEC with respect to a registered offer to exchange the original series D notes for a series of exchange notes that will be issued under the same indenture, in the same aggregate principal amount as and with terms that are substantially identical in all material respects to the original series D notes except that they will not contain terms with respect to transfer restrictions;
•  use our reasonable best efforts to cause the exchange offer registration statement to become effective under the Securities Act within 270 days after the date on which we issued the original series D notes; and
•  promptly after the exchange offer registration statement is declared effective, offer the series D exchange notes in exchange for surrender of the original series D notes.

We will be entitled to consummate the exchange offer on the expiration date provided that we have accepted all original series D notes previously validly tendered in accordance with the terms set forth in this prospectus and the applicable letter of transmittal.

In addition, under certain circumstances described below, we may be required to file a shelf registration statement to cover resales of the series D notes.

If we do not comply with certain of our obligations under the registration rights agreement, we must pay liquidated damages on the original series D notes in addition to the interest that is otherwise due on the series D notes. See "— Liquidated Damages." The purpose of the exchange offer is to fulfill our obligations with respect to the registration rights agreement.

If you are a broker-dealer that receives series D exchange notes for its own account in exchange for original series D notes, where you acquired such original series D notes as a result of market-making activities or other trading activities, you must acknowledge that you will deliver a prospectus in connection with any resale of such series D exchange notes. See "Plan of Distribution."

Terms of the Exchange

Upon the terms and subject to the conditions contained in this prospectus and in the letters of transmittal that accompany this prospectus, we are offering to exchange $1,000 in principal amount of series D exchange notes for each $1,000 in principal amount of original series D notes. The terms of the series D exchange notes are substantially identical to the terms of the original series D notes except that the series D exchange notes will generally be freely transferable. The series D exchange notes will evidence the same debt as the original series D notes and will be entitled to the benefits of the indenture. Any original series D notes that remain outstanding after the consummation of the exchange offer, together with all series D exchange notes issued in connection with the exchange offer, will be treated as a single class of securities under the indenture. See "Description of Notes."

The exchange offer is not conditioned on any minimum aggregate principal amount of original series D notes being tendered for exchange.

Based on existing interpretations of the Securities Act by the staff of the SEC set forth in several no-action letters to third parties, and subject to the immediately following sentence, we believe that you may offer for resale, resell and otherwise transfer the series D exchange notes without further compliance with the registration and prospectus delivery provisions of the Securities Act. However, if you are an "affiliate" (within the meaning of the Securities Act) of ours or you intend to participate in

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the exchange offer for the purpose of distributing the series D exchange notes or you are a broker-dealer (within the meaning of the Securities Act) that acquired series D notes in a transaction other than as part of its market-making or other trading activities and who has arranged or has an understanding with any person to participate in the distribution of the series D exchange notes, you:

(1)  will not be able to rely on the interpretations by the staff of the SEC set forth in the above-mentioned no-action letters;
(2)  will not be able to tender your series D notes in the exchange offer; and
(3)  must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of your series D notes unless such sale or transfer is made pursuant to an exemption from such requirements.

Subject to exceptions for certain holders, to participate in the exchange offer you will be required to represent to us at the time of the consummation of the exchange offer, among other things, that: (1) you are not an affiliate of ours; (2) any series D exchange notes to be received by you will be acquired in the ordinary course of your business; and (3) at the time of commencement of the exchange offer, you have no arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of the series D notes. In addition, in connection with any resales of series D exchange notes, any broker-dealer who acquired series D exchange notes for its own account as a result of market-making activities or other trading activities must deliver a prospectus meeting the requirements of the Securities Act. The SEC has taken the position that such a broker-dealer may fulfill its prospectus delivery requirements with respect to the series D exchange notes (other than a resale of an unsold allotment from the initial sale of the original series D notes) with this prospectus. Under the registration rights agreement, we are required to allow a broker-dealer and other persons with similar prospectus delivery requirements, if any, to use this prospectus connection with the resale of such series D exchange notes for a period of time not less than 120 days following the consummation of the exchange offer. If you are a broker-dealer that receives series D exchange notes for its own account in exchange for original series D notes, where you acquired such original series D notes as a result of market-making activities or other trading activities, you must acknowledge that you will deliver a prospectus in connection with any resale of such series D exchange notes. See "Plan of Distribution."

You will not be required to pay brokerage commissions or fees or, subject to the instructions in the applicable letter of transmittal, transfer taxes relating to your exchange of original series D notes for series D exchange notes in the exchange offer.

Shelf Registration Statement

If:

•  we are not permitted to effect the exchange offer because of any change in law or in applicable interpretations of such law by the staff of the SEC;
•  the exchange offer is not consummated by the 40th day after the date on which the exchange offer registration statement was declared effective;
•  any of the initial purchasers of the original series D notes so requests with respect to the original series D notes not eligible to be exchanged for series D exchange notes in the exchange offer and held by it following the consummation of exchange offer;
•  any holder of series D notes (other than a broker-dealer electing to exchange original series D notes acquired for its own account as a result of market-making or other trading activities for exchange securities) is not eligible to participate in the exchange offer and any such holder so requests for any reason other than the failure by such holder to make a timely and valid tender in accordance with the terms of exchange offer; or
•  any holder of series D notes (other than a broker-dealer electing to exchange original series D notes acquired for its own account as a result of market-making or other trading activities for series D exchange notes) participates in the exchange offer but does not receive freely

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  tradable series D exchange notes on the date of the exchange and any such holder so requests for any reason other than the failure by such holder to make a timely and valid tender in accordance with the terms of exchange offer,

we will:

•  as promptly as practicable prepare and file with the SEC a shelf registration statement relating to the offer and sale of series D notes that are not otherwise freely tradable;
•  use our reasonable best efforts to cause the shelf registration statement to be declared effective not later than the later to occur of the date that is 150 days after the date on which our obligation to file the shelf registration arises or 270 days after the date on which we issued the original series D notes; and
•  use our reasonable best efforts to keep the shelf registration statement continuously effective until the earlier of two years from the date on which we issued the original series D notes (subject to extension under certain circumstances) and such shorter period ending when all the series D notes covered by the shelf registration statement have been sold pursuant to the shelf registration statement or are no longer restricted securities (as defined in Rule 144 under the Securities Act).

You will not be entitled, except if you were an initial purchaser of the original series D notes, to have your series D notes registered under the shelf registration statement, unless you agree in writing to be bound by the applicable provisions of the registration rights agreement. In order to sell your series D notes under the shelf registration statement, you generally must be named as a selling security holder in the related prospectus and must deliver a prospectus to purchasers. Consequently, you will be subject to the civil liability provisions under the Securities Act in connection with those sales and indemnification obligations under the registration rights agreements.

Liquidated Damages

A registration default will be deemed to have occurred if:

(1)  the exchange offer registration statement is not declared effective within 270 days after the date on which we issued the original series D notes;
(2)  the shelf registration statement is not declared effective by the later to occur of the date that is 150 days after the date on which our obligation to file the shelf registration arises or 270 days after the date on which we issued the original series D notes; or
(3)  after either the exchange offer registration statement or the shelf registration statement is declared effective, such registration statement or the related prospectus thereafter ceases to be effective or usable (subject to certain exceptions) in connection with resales of original series D notes or series D exchange notes for the periods specified and in accordance with the registration rights agreement.

Additional interest will accrue on the series D notes subject to such registration default at a rate of 0.5% from and including the date on which any such registration default occurs to but excluding the date on which all such registration defaults have ceased to be continuing. In each case, such additional interest is payable in addition to any other interest payable from time to time with respect to the original series D notes and the series D exchange notes. The series D exchange notes will not contain any provisions regarding the payment of liquidated damages.

Expiration Date; Extensions; Termination; Amendments

The exchange offer expires on the expiration date. The expiration date is 5:00 p.m., New York City time, on April 2, 2004, unless we in our sole discretion extend the period during which the exchange offer is open, in which event the expiration date is the latest time and date on which the exchange offer, as so extended by us, expires. We reserve the right to extend the exchange offer at any time and from time to time prior to the expiration date by giving written notice to The Bank of New

22



York, as the exchange agent, and by timely public announcement communicated in accordance with applicable law or regulation. During any extension of the exchange offer, all original series D notes previously tendered pursuant to the exchange offer and not validly withdrawn will remain subject to the exchange offer.

The exchange date will occur promptly after the expiration date. We expressly reserve the right to (i) terminate the exchange offer and not accept for exchange any original series D notes for any reason, including if any of the events set forth below under "— Conditions to the Exchange Offer" shall have occurred and shall not have been waived by us and (ii) amend the terms of the exchange offer in any manner, whether before or after any tender of the original series D notes. If any such termination or amendment occurs, we will notify the exchange agent in writing and will either issue a press release or give written notice to the holders of the original series D notes as promptly as practicable. Unless we terminate the exchange offer prior to 5:00 p.m., New York City time, on the expiration date, we will exchange the series D exchange notes for the original series D notes on the exchange date.

If we waive any material condition to the exchange offer, or amend the exchange offer in any other material respect, and if at the time that notice of such waiver or amendment is first published, sent or given to holders of original series D notes in the manner specified above, the exchange offer is scheduled to expire at any time earlier than the expiration of a period ending on the fifth business day from, and including, the date that such notice is first so published, sent or given, then the exchange offer will be extended until the expiration of such period of five business days.

This prospectus and the related letters of transmittal and other relevant materials will be mailed by us to record holders of original series D notes and will be furnished to brokers, banks and similar persons whose names, or the names of whose nominees, appear on the lists of holders for subsequent transmittal to beneficial owners of original series D notes.

How to Tender

The tender to us of original series D notes by you pursuant to one of the procedures set forth below will constitute an agreement between you and us in accordance with the terms and subject to the conditions set forth herein and in the applicable letter of transmittal.

General Procedures.    A holder of an original series D note may tender the same by (i) properly completing and signing the applicable letter of transmittal or a facsimile thereof (all references in this prospectus to the letter of transmittal shall be deemed to include a facsimile thereof) and delivering the same, together with the certificate or certificates representing the original series D notes being tendered and any required signature guarantees (or a timely confirmation of a book-entry transfer, which we refer to as a Book-Entry Confirmation, pursuant to the procedure described below), to the exchange agent at its address set forth on the back cover of this prospectus on or prior to the expiration date or (ii) complying with the guaranteed delivery procedures described below.

If tendered original series D notes are registered in the name of the signer of the letter of transmittal and the series D exchange notes to be issued in exchange therefor are to be issued (and any untendered original series D notes are to be reissued) in the name of the registered holder, the signature of such signer need not be guaranteed. In any other case, the tendered original series D notes must be endorsed or accompanied by written instruments of transfer in form satisfactory to us and duly executed by the registered holder and the signature on the endorsement or instrument of transfer must be guaranteed by a firm, which we refer to as an Eligible Institution, that is a member of a recognized signature guarantee medallion program, which we refer to as an Eligible Program, within the meaning of Rule 17Ad-15 under the Securities and Exchange Act of 1934. If the series D exchange notes and/or original series D notes not exchanged are to be delivered to an address other than that of the registered holder appearing on the note register for the original series D notes, the signature on the letter of transmittal must be guaranteed by an Eligible Institution.

Any beneficial owner whose original series D notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and who wishes to tender original series D notes

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should contact such holder promptly and instruct such holder to tender original series D notes on such beneficial owner's behalf. If such beneficial owner wishes to tender such original series D notes himself, such beneficial owner must, prior to completing and executing the letter of transmittal and delivering such original series D notes, either make appropriate arrangements to register ownership of the original series D notes in such beneficial owner's name or follow the procedures described in the immediately preceding paragraph. The transfer of record ownership may take considerable time.

Book-Entry Transfer.    The exchange agent will make a request to establish an account with respect to the original series D notes at The Depository Trust Company, which we refer to as the Book-Entry Transfer Facility, for purposes of the exchange offer within two business days after receipt of this prospectus, and any financial institution that is a participant in the Book-Entry Transfer Facility's systems may make book-entry delivery of original series D notes by causing the Book-Entry Transfer Facility to transfer such original series D notes into the exchange agent's account at the Book-Entry Transfer Facility in accordance with the Book-Entry Transfer Facility's procedures for transfer. However, although delivery of original series D notes may be effected through book-entry transfer at the Book-Entry Transfer Facility, the letter of transmittal, with any required signature guarantees and any other required documents, must, in any case, be transmitted to and received by the exchange agent at the address specified on the back cover page of this prospectus on or prior to the expiration date or the guaranteed delivery procedures described below must be complied with.

The method of delivery of original series D notes and all other documents is at your election and risk. If sent by mail, we recommend that you use registered mail, return receipt requested, obtain proper insurance, and complete the mailing sufficiently in advance of the expiration date to permit delivery to the exchange agent on or before the expiration date.

Guaranteed Delivery Procedures.    If a holder desires to accept the exchange offer and time will not permit a letter of transmittal or original series D notes to reach the exchange agent before the expiration date, a tender may be effected if the exchange agent has received at its office listed on the back cover hereof on or prior to the expiration date a letter, telegram or facsimile transmission from an Eligible Institution setting forth the name and address of the tendering holder, the names in which the original series D notes are registered, the principal amount of the original series D notes and, if possible, the certificate numbers of the original series D notes to be tendered, and stating that the tender is being made thereby and guaranteeing that within three New York Stock Exchange trading days after the date of execution of such letter, telegram or facsimile transmission by the Eligible Institution, the original series D notes, in proper form for transfer, will be delivered by such Eligible Institution together with a properly completed and duly executed letter of transmittal (and any other required documents). Unless original series D notes being tendered by the above-described method (or a timely Book-Entry Confirmation) are deposited with the exchange agent within the time period set forth above (accompanied or preceded by a properly completed letter of transmittal and any other required documents), we may, at our option, reject the tender. Copies of a Notice of Guaranteed Delivery which may be used by Eligible Institutions for the purposes described in this paragraph are being delivered with this prospectus and the related letter of transmittal.

A tender will be deemed to have been received as of the date when the tendering holder's properly completed and duly signed letter of transmittal accompanied by the original series D notes (or a timely Book-Entry Confirmation) is received by the exchange agent. Issuances of series D exchange notes in exchange for original series D notes tendered pursuant to a Notice of Guaranteed Delivery or letter, telegram or facsimile transmission to similar effect (as provided above) by an Eligible Institution will be made only against deposit of the letter of transmittal (and any other required documents) and the tendered original series D notes (or a timely Book-Entry Confirmation).

All questions as to the validity, form, eligibility (including time of receipt) and acceptance for exchange of any tender of original series D notes will be determined by us and our determination will be final and binding. We reserve the absolute right to reject any or all tenders not in proper form or the acceptances for exchange of which may, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any of the conditions of the exchange offer or any defect or irregularities in tenders of any particular holder whether or not similar defects or irregularities are

24



waived in the case of other holders. None of us, the exchange agent or any other person will be under any duty to give notification of any defects or irregularities in tenders or shall incur any liability for failure to give any such notification. Our interpretation of the terms and conditions of the exchange offer (including the letters of transmittal and the instructions thereto) will be final and binding.

Terms and Conditions of the Letters of Transmittal

The letters of transmittal contain, among other things, the following terms and conditions, which are part of the exchange offer.

The party tendering original series D notes for exchange, whom we refer to as the Transferor, exchanges, assigns and transfers the original series D notes to us and irrevocably constitutes and appoints the exchange agent as the Transferor's agent and attorney-in-fact to cause the original series D notes to be assigned, transferred and exchanged. The Transferor represents and warrants that it has full power and authority to tender, exchange, assign and transfer the original series D notes and to acquire series D exchange notes issuable upon the exchange of such tendered original series D notes, and that, when the same are accepted for exchange, we will acquire good and unencumbered title to the tendered original series D notes, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claim. The Transferor also warrants that it will, upon request, execute and deliver any additional documents deemed by us to be necessary or desirable to complete the exchange, assignment and transfer of tendered original series D notes. The Transferor further agrees that acceptance of any tendered original series D notes by us and the issuance of series D exchange notes in exchange therefor shall constitute performance in full by us of our obligations under the registration rights agreement and that we shall have no further obligations or liabilities thereunder (except in certain limited circumstances). All authority conferred by the Transferor will survive the death or incapacity of the Transferor and every obligation of the Transferor shall be binding upon the heirs, legal representatives, successors, assigns, executors and administrators of such Transferor.

See "— Terms of the Exchange."

Withdrawal Rights

Original series D notes tendered pursuant to the exchange offer may be withdrawn at any time prior to the expiration date. For a withdrawal to be effective, a written or facsimile transmission notice of withdrawal must be timely received by the exchange agent at its address set forth on the back cover of this prospectus. Any such notice of withdrawal must specify the person named in the letter of transmittal as having tendered original series D notes to be withdrawn, the certificate numbers of original series D notes to be withdrawn, the principal amount of original series D notes to be withdrawn (which must be an authorized denomination), a statement that such holder is withdrawing his election to have such original series D notes exchanged, and the name of the registered holder of such original series D notes, and must be signed by the holder in the same manner as the original signature on the letter of transmittal (including any required signature guarantees) or be accompanied by evidence satisfactory to us that the person withdrawing the tender has succeeded to the beneficial ownership of the original series D notes being withdrawn. The exchange agent will return the properly withdrawn original series D notes promptly following receipt of notice of withdrawal. All questions as to the validity of notices of withdrawals, including time of receipt, will be determined by us, and our determination will be final and binding on all parties.

Acceptance of Original Notes for Exchange; Delivery of Exchange Notes

Upon the terms and subject to the conditions of the exchange offer, the acceptance for exchange of original series D notes validly tendered and not withdrawn and the issuance of the series D exchange notes will be made on the exchange date. For the purposes of the exchange offer, we shall be deemed to have accepted for exchange validly tendered original series D notes when, as and if we have given written notice thereof to the exchange agent.

The exchange agent will act as agent for the tendering holders of original series D notes for the purposes of receiving series D exchange notes from us and causing the original series D notes to be

25



assigned, transferred and exchanged. Upon the terms and subject to the conditions of the exchange offer, delivery of series D exchange notes to be issued in exchange for accepted original series D notes will be made by the exchange agent promptly after acceptance of the tendered original series D notes. Original series D notes not accepted for exchange by us will be returned without expense to the tendering holders (or in the case of original series D notes tendered by book-entry transfer into the exchange agent's account at the Book-Entry Transfer Facility pursuant to the procedures described above, such non-exchanged original series D notes will be credited to an account maintained with such Book-Entry Transfer Facility) promptly following the expiration date or, if we terminate the exchange offer prior to the expiration date, promptly after the exchange offer is so terminated.

Conditions to the Exchange Offer

We are not required to accept for exchange, or to issue series D exchange notes in exchange for, any outstanding original series D notes. We may terminate or extend the exchange offer by oral or written notice to the exchange agent and by timely public announcement communicated in accordance with applicable law or regulation, if:

•  any federal law, statute, rule, regulation or interpretation of the staff of the SEC has been proposed, adopted or enacted that, in our judgment, might impair our ability to proceed with the exchange offer or otherwise make it inadvisable to proceed with the exchange offer;
•  an action or proceeding has been instituted or threatened in any court or by any governmental agency that, in our judgment might impair our ability to proceed with the exchange offer or otherwise make it inadvisable to proceed with the exchange offer;
•  there has occurred a material adverse development in any existing action or proceeding that might impair our ability to proceed with the exchange offer or otherwise make it inadvisable to proceed with the exchange offer;
•  any stop order is threatened or in effect with respect to the registration statement of which this prospectus is a part or the qualification of the indenture under the Trust Indenture Act of 1939;
•  all governmental approvals that we deem necessary for the consummation of the exchange offer have not been obtained;
•  there is a change in the current interpretation by the staff of the SEC which permits holders who have made the required representations to us to resell, offer for resale, or otherwise transfer series D exchange notes issued in the exchange offer without registration of the series D exchange notes and delivery of a prospectus; or
•  a material adverse change shall have occurred in our business, condition, operations or prospects.

The foregoing conditions are for our sole benefit and may be asserted by us with respect to all or any portion of the exchange offer regardless of the circumstances (including any action or inaction by us) giving rise to such condition or may be waived by us in whole or in part at any time or from time to time in our sole discretion. The failure by us at any time to exercise any of the foregoing rights will not be deemed a waiver of any such right, and each right will be deemed an ongoing right which may be asserted at any time or from time to time. In addition, we have reserved the right, notwithstanding the satisfaction of each of the foregoing conditions, to terminate or amend the exchange offer.

Any determination by us concerning the fulfillment or non-fulfillment of any conditions will be final and binding upon all parties.

Exchange Agent

The Bank of New York has been appointed as the exchange agent for the exchange offer. Letters of transmittal must be addressed to the exchange agent at its address set forth on the back cover page of this prospectus. Delivery to an address other than as set forth herein, or transmissions of instructions via a facsimile or telex number other than the ones set forth herein, will not constitute a valid delivery.

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Solicitation of Tenders; Expenses

We have not retained any dealer-manager or similar agent in connection with the exchange offer and will not make any payments to brokers, dealers or others for soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and will reimburse it for reasonable out-of-pocket expenses in connection therewith. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding tenders for their customers. The expenses to be incurred in connection with the exchange offer, including the fees and expenses of the exchange agent and printing, accounting and legal fees, will be paid by us and are estimated at approximately $250,000.

No dealer, salesperson or other individual has been authorized to give any information or to make any representations not contained in this prospectus in connection with the exchange offer. If given or made, such information or representations must not be relied upon as having been authorized by us. Neither the delivery of this prospectus nor any exchange made hereunder shall, under any circumstances, create any implication that there has been no change in our affairs since the respective dates as of which information is given herein.

The exchange offer is not being made to (nor will tenders be accepted from or on behalf of) holders of original series D notes in any jurisdiction in which the making of the exchange offer or the acceptance thereof would not be in compliance with the laws of such jurisdiction. However, we may, at our discretion, take such action as we may deem necessary to make the exchange offer in any such jurisdiction and extend the exchange offer to holders of original series D notes in such jurisdiction. In any jurisdiction the securities laws or blue sky laws of which require the exchange offer to be made by a licensed broker or dealer, the exchange offer is being made on behalf of us by one or more registered brokers or dealers which are licensed under the laws of such jurisdiction.

Appraisal Rights

You will not have appraisal rights in connection with the exchange offer.

Federal Income Tax Consequences

The exchange of original series D notes for series D exchange notes will not be a taxable exchange for U.S. federal income tax purposes, and holders will not recognize any taxable gain or loss or any interest income as a result of such exchange. See "Certain United States Federal Income Tax Considerations."

Other

Participation in the exchange offer is voluntary and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decisions on what action to take.

As a result of the making of, and upon acceptance for exchange of all validly tendered original series D notes pursuant to the terms of this exchange offer, we will have fulfilled a covenant contained in the terms of the original series D notes and the registration rights agreement. Holders of the original series D notes who do not tender their original series D notes in the exchange offer will continue to hold such original series D notes and will be entitled to all the rights, and limitations applicable thereto, under the indenture, except for any such rights under the registration rights agreement which by their terms terminate or cease to have further effect as a result of the making of this exchange offer. See "Description of Notes." All untendered original series D notes will continue to be subject to the restriction on transfer set forth in the indenture. To the extent that original series D notes are tendered and accepted in the exchange offer, the trading market, if any, for the original series D notes could be adversely affected. See "Risk Factors — Your ability to sell your original series D notes may be significantly more limited and the price at which you may be able to sell your original series D notes may be significantly lower if you do not exchange them for registered series D exchange notes in the exchange offer."

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We may in the future seek to acquire untendered original series D notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plan to acquire any original series D notes which are not tendered in the exchange offer.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

The following tables set forth selected historical consolidated financial and operating data, which should be read in conjunction with our financial statements and the related notes to those statements included in this prospectus and with "Management's Discussion and Analysis of Financial Condition and Results of Operations" appearing elsewhere in this prospectus. The selected historical consolidated financial and operating data as of and for the years ended December 31, 2003, 2002 and 2001, as of December 31, 2000 and for the period from March 14, 2000 through December 31, 2000 have been derived from our historical consolidated financial statements. The selected historical consolidated financial and operating data for the period from January 1, 2000 through March 13, 2000 and as of and for the year ended December 31, 1999 have been derived from our predecessor's historical consolidated financial statements. All amounts (except for ratios) are presented in millions.


    March 14, 2000
through
December 31,
2000(3)		 Our Predecessor
  Year Ended December 31, January 1, 2000
through
March 13, 2000 (4)		 Year Ended
December 31,
1999(5)
  2003 2002(1) 2001(2)
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  
                                     
OTHER FINANCIAL DATA:                                    
Ratio of earnings to fixed charges(6)   2.0x     1.9x     1.8x     1.3x     1.7x     1.6x  
                                     
BALANCE SHEET DATA:                                    
Total assets(7) $ 19,168.2   $ 18,439.9   $ 12,994.6   $ 11,960.4     N/A   $ 11,084.8  
Parent company senior debt(8)   2,777.9     2,323.4     1,834.5     1,830.0     N/A     1,856.3  
Parent company subordinated debt(8)   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(8)   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, or TPL, asset valuation impairment charge.
(3)  Reflects the Teton Transaction on March 14, 2000. See "Business — General."
(4)  Includes $7.6 million of expenses related to the Teton Transaction. See "Business — General."
(5)  Reflects our acquisition of MidAmerican Energy on March 12, 1999, our disposition of the Coso Joint Ventures on February 26, 1999, and our disposition of a 50% ownership interest in CE Generation, LLC, or 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 our investment in Indonesia, gains on sales of shares of McLeodUSA, CE Electric UK restructuring charges and transaction costs related to our acquisition by a private investor group.

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(6)  For purposes of computing the ratio of earnings to fixed charges, earnings are divided by fixed charges. Earnings represent the aggregate of (a) our pre-tax income and (b) fixed charges, less capitalized interest. Fixed charges represent interest (whether expensed or capitalized), amortization of deferred financing and bank fees, and the estimated interest component of rentals.
(7)  We originally filed our Annual Report on Form 10-K on February 9, 2004. In accordance with accounting guidance issued subsequent to that date, we have 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.
(8)  Excludes current portion.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management's discussion and analysis of certain significant factors which have affected the financial condition and results of operations of MidAmerican Energy Holdings Company, or MEHC, and its direct and indirect subsidiaries, or together with MEHC, MidAmerican, during the periods included in the accompanying statements of operations. This discussion should be read in conjunction with "Selected Consolidated Financial and Operating Data" and MEHC's historical consolidated financial statements and the notes to those statements included elsewhere in this prospectus.

General

MEHC is a United States-based privately owned global energy company with publicly held fixed income securities that, through its subsidiaries, generates, distributes and supplies energy to utilities, government entities, retail customers and other customers located throughout the world. MidAmerican's operations are organized and managed on seven distinct platforms: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK (which includes Northern Electric and Yorkshire), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and HomeServices.

Through these platforms, MidAmerican 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.

MidAmerican's principal energy subsidiaries generate, transmit, store, distribute and supply energy. MidAmerican'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. MidAmerican 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, MidAmerican 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 Water and Energy Company, Inc., or CE Casecnan, an indirect subsidiary of ours, commenced operations on December 11, 2001.

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•  In 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, MidAmerican'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.

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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 Yorkshire 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 National Irrigation Administration, or NIA, Arbitration settlement, equity allowance for funds used during construction, or 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 Northern Electric Distribution Limited, or 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

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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 MidAmerican adopted FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities", or 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 Yorkshire trust 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 MidAmerican 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

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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 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 Electricity Distribution plc, or YED.

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.

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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 MidAmerican'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 Recovery project (see "Business — CalEnergy Generation – Domestic — Zinc Recovery 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 CE Casecnan project, the Cordova Energy Company, LLC project, or 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

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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, MidAmerican 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

MidAmerican 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. MidAmerican 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, MidAmerican's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

MidAmerican'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, MidAmerican 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

MidAmerican 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.

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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

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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

MidAmerican's subsidiary CE Obsidian Energy LLC, or 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, or IID, pursuant to a power purchase agreement. Transalta USA Inc., or 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, MidAmerican 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.

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Northern Natural Gas

In August 2002, MidAmerican 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 MidAmerican in March 2002 for $275.0 million.

Put of ROP Bond and Receipt of Cash

On January 14, 2004, CE Casecnan exercised its right to put the Republic of the Philippines, or ROP, 8.375% Note due 2013 held by it 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.

Cash Flows from Financing Activities

Cash flows used in financing activities for 2003 were $426.3 million. During 2003, MidAmerican 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, MidAmerican 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.

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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, or SSFC, a wholly owned subsidiary of CE Generation, announced its election to redeem an aggregate principal amount of approximately $136.4 million of the Salton Sea Series F Bonds, pro rata, at a redemption price of 100% of such aggregate outstanding principal amount, plus accrued interest to the date of redemption. The redemption was completed on March 1, 2004. As a result, MEHC no longer has any liability with respect to its guarantee of the Salton Sea Series F Bonds.

On February 12, 2004, MEHC issued $250 million of its 5.00% Senior Notes which mature on February 14, 2014. Approximately $138.9 million of the net proceeds were used to fund the redemption by SSFC of the Salton Sea Series F Bonds as described in the immediately preceding paragraph. The balance of the net proceeds will be used for general corporate purposes.

Credit Ratings Risks

Debt and preferred securities of MidAmerican 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. MidAmerican 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

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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 MidAmerican 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 MidAmerican's costs.

Obligations and Commitments

MidAmerican 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 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.

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Off-Balance Sheet Arrangements

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

As of December 31, 2003, MidAmerican'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, MidAmerican'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 guaranteed on the Salton Sea Funding Series F Bonds and which is included in MidAmerican's consolidated balance sheet at December 31, 2003. This amount was redeemed on March 1, 2004. As of December 31, 2003, MidAmerican'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, MidAmerican adopted Statement of Financial Accounting Standards, or 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 MidAmerican was immaterial.

MidAmerican identified legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. On January 1, 2003, MidAmerican recorded $289.3 million of asset retirement obligation, or 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", or 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 MidAmerican for contracts entered into or modified after June 30, 2003. The adoption of SFAS 149 did not have a material effect on MidAmerican'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", or 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 MidAmerican for fiscal periods beginning after December 15, 2003. The adoption of SFAS 150 is not expected to have a material effect on MidAmerican'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, or FIN 46, and provided additional guidance surrounding the application of FIN

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46. MidAmerican 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, MidAmerican 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. MidAmerican 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. MidAmerican is currently evaluating the impact of FIN 46R on several operating joint ventures that MidAmerican currently does not consolidate.

Critical Accounting Policies

The preparation of financial statements and related documents in conformity with GAAP requires management to make judgments, assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Note 2 to the consolidated financial statements for the year ended December 31, 2003 included in this prospectus describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of long-lived assets, contingent liabilities, accrued pension and post-retirement expense and revenue. Actual results could differ from these estimates. The following critical accounting policies are impacted significantly by judgments, assumptions and estimates used in the preparation of the consolidated financial statements.

Accounting for the Effects of Certain Types of Regulation

MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial statements in accordance with the provisions of SFAS 71, which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural Gas have deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or payment of such obligations is no longer probable as a result of changes in regulation, the associated regulatory asset or liability is charged or credited to income.

A possible consequence of deregulation of the regulated energy industry is that SFAS 71 may no longer apply. If portions of MidAmerican's regulated energy operations no longer meet the criteria of SFAS 71, MidAmerican 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.

MidAmerican 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

MidAmerican'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. MidAmerican believes the useful lives assigned to the depreciable assets, which generally range from 3 to 87 years, are reasonable.

MidAmerican'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

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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 MidAmerican 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. MidAmerican 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 MidAmerican 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, MidAmerican adopted SFAS No. 142, "Goodwill and Other Intangible Assets", or 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. MidAmerican's related amortization consists solely of goodwill amortization. In accordance with SFAS 142, MidAmerican 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

MidAmerican 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. MidAmerican 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.

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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.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MidAmerican 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, MidAmerican enters into various financial derivative instruments. Senior management provides the overall direction, structure, conduct and control of MidAmerican'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, MidAmerican 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 MidAmerican 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 MidAmerican were to reacquire all or a portion of these instruments prior to their maturity.

At December 31, 2002, MidAmerican 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 MidAmerican to the risk of earnings loss due to changes in market interest rates.

At December 31, 2003, MidAmerican had floating-rate obligations of $459.8 million that expose MidAmerican 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% MidAmerican'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, MidAmerican had floating-rate obligations of $425.1 million that expose MidAmerican 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 MidAmerican 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 MidAmerican would expect to pay if these agreements were terminated.

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A decrease of 10% in the December 31, 2003 rate of exchange of sterling to dollars would increase the amount owed by MidAmerican 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 ) 

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BUSINESS

General

We are a United States-based privately owned global energy company. Our operations are organized and managed on seven distinct platforms: MidAmerican Energy Company, or MidAmerican Energy, Kern River Gas Transmission Company, or Kern River, Northern Natural Gas Company, or Northern Natural Gas, CE Electric UK Funding, or CE Electric UK (which includes Northern Electric plc, or Northern Electric, and Yorkshire Electricity Group plc, or Yorkshire) CalEnergy Generation – Domestic (our interests in independent power projects and related operations), CalEnergy Generation – Foreign (our subsidiaries owning the Upper Mahiao, Malitbog and Mahanagdong projects (or collectively, the Leyte Projects) and the CE Casecnan project) and HomeServices of America, Inc., or with its subsidiaries, HomeServices. See Note 20 to our consolidated financial statements for additional segment information regarding our platforms. Through these platforms, we own and operate 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.

Our energy subsidiaries generate, transmit, store, distribute and supply energy. Our electric and natural gas utility subsidiaries currently serve approximately 4.4 million electricity customers and approximately 670,000 natural gas customers. Our 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. We have 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 (as further described in "Business — MidAmerican Energy — Electric Operations") 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.

On March 14, 2000, we and an investor group comprised of Berkshire Hathaway, Walter Scott, Jr., one of our directors, David L. Sokol, our Chairman and Chief Executive Officer, and Gregory E. Abel, our President and Chief Operating Officer, 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 our outstanding common stock in a transaction referred to in this prospectus as the Teton Transaction.

Our principal executive offices are located at 666 Grand Avenue, Des Moines, Iowa 50309 and our telephone number is (515) 242-4300. We initially incorporated in 1971 under the laws of the State of Delaware and were reincorporated in 1999 in Iowa, at which time we changed our name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.

MidAmerican Energy

Business

Through MidAmerican Energy, we own 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.

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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.

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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 Commercial
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, or 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

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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 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., or 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 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%.

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MidAmerican Energy's transmission system connects its generating facilities with distribution substations and interconnects with 14 other transmission providers in Iowa and five adjacent states. Under normal operating conditions, MidAmerican Energy's transmission system has adequate capacity to deliver energy to MidAmerican Energy's distribution system and to export and import energy with other interconnected systems.

Gas Operations

MidAmerican Energy 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, or NGPL, Northern Border Pipeline Company, or Northern Border, and ANR Pipeline Company, or 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 March 1, 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, we own 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.

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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, or 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 an agreed formula with respect to any 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, or 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, or 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

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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, we own 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 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 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

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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, or 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, or Colorado Interstate, and from Canadian production areas through Northern Border, Great Lakes Gas Transmission Limited Partnership, or Great Lakes and Viking Gas Transmission Company, or 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

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comparatively lower costs and will require significantly less capital expenditure to comply with the Pipeline Safety Improvement Act of 2002, or 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, we and a recently formed subsidiary, Alaska Gas Transmission Company, LLC, or Alaska Gas, filed an application with the State of Alaska Department of Revenue for approval under the Alaska Stranded Gas Development Act, or 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, we 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. We, Alaska Gas, and two unaffiliated parties holding rights to acquire up to a combined aggregate of 19.9% of Alaska Gas's economic interest, have commenced negotiations with the State of Alaska.

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CE Electric UK

Business

Through CE Electric UK, we own, among other things, two companies that distribute electricity in the United Kingdom, NED and 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, or Innogy, and simultaneously sold Northern Electric's electricity and gas supply and metering businesses to Innogy. We sometimes refer 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, or 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, or 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, or CE Gas, CE Electric UK's indirect subsidiary, is a gas exploration and production company that is focused on developing integrated upstream gas projects.

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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, 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, or 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.

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CalEnergy Generation – Domestic

Business

Through CalEnergy Generation – Domestic, we own interests in 15 operating non-utility power projects in the United States. The following table sets out certain information concerning CalEnergy Generation – Domestic's non-utility power projects in operation as of December 31, 2003:


Operating Project Facility Net
Capacity
(MW)(1)		 Net MW
Owned (1)		 Fuel Location Power
Purchase
Agreement
Expiration		 Power
Purchaser(2)
Cordova   537     537     Gas   Illinois 2017 El Paso/MidAmerican Energy
Salton Sea I   10     5     Geo   California 2017 Edison
Salton Sea II   20     10     Geo   California 2020 Edison
Salton Sea III   50     25     Geo   California 2019 Edison
Salton Sea IV   40     20     Geo   California 2026 Edison
Salton Sea V   49     25     Geo   California Varies TransAlta/Minerals/Riverside (3)
Vulcan   34     17     Geo   California 2016 Edison
Elmore   38     19     Geo   California 2018 Edison
Leathers   38     19     Geo   California 2019 Edison
Del Ranch   38     19     Geo   California 2019 Edison
CE Turbo   10     5     Geo   California Varies TransAlta/Minerals(3)
Saranac   240     90     Gas   New York 2009 NYSE&G
Power Resources(4)   212     106     Gas   Texas 2005 ONEOK
Yuma   50     25     Gas   Arizona 2024 SDG&E
Roosevelt Hot Springs (5)   23     17     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, or El Paso; Southern California Edison Company, or Edison; TransAlta USA Inc., or TransAlta; CalEnergy Minerals LLC, or Minerals; the City of Riverside, California, or Riverside; New York State Electric & Gas Corporation, or NYSE&G; ONEOK Energy, Marketing and Trading Company, L.P., or ONEOK; San Diego Gas & Electric Company, or SDG&E; and Utah Power & Light Company, or 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, or Salton Sea Power, which owns Salton Sea V, and CE Turbo LLC, or 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 agreement will 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. 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, or QF, within the meaning of the Public Utility Regulatory Policies Act of 1978, as amended, or

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PURPA under the TXU Power Generation Company, LP, or TXU, Power Purchase Agreement, which expired September 30, 2003. The net capacity increased to 212 MW during operations as an exempt wholesale generator, or 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 ours, 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 which we refer to as Cordova project. CalEnergy Generation Operating Company, an indirect wholly owned subsidiary of ours, 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. We are 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.

We have a 50% ownership interest in CE Generation, whose direct and indirect subsidiaries currently operate ten geothermal plants in the Imperial Valley in California which we refer to as 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, or 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, or Edison's 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

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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 agreement governing this sale will 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., or 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. We 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. We guarantee 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

Our 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

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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

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 California Energy Commission, or CEC, gave final approval for construction of the facility.

CalEnergy Generation – Foreign

Business

The CalEnergy Generation – Foreign platform consists of our 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 CE 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, or PNOC-EDC, ROP, and the NIA. NIA also pays CE Casecnan 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. See "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., or CE Cebu, a Philippine corporation that is 100% indirectly owned by us. 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

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"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, or 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., or CE Luzon, a Philippine corporation of which we indirectly own 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, or VGPC, a Philippine general partnership that is indirectly wholly owned by us. 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 CE Casecnan project, a combined irrigation and hydroelectric power generation project. The CE Casecnan project consists generally of diversion structures in the Casecnan and Taan rivers that capture and divert excess water in the Casecnan

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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 CE 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, which we refer to as 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 prospectus). 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 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 which we refer to as 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 CE 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 CE 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.

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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 CE 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, or 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 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 CE 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 CE 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,

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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

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. 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.

Employees

As of December 31, 2003, we employed approximately 11,440 people, of which approximately 3,820 were represented by labor unions.

Properties

Our 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 us are in good operating condition and well maintained. Pursuant to separate financing agreements, substantially all or most of the properties of each of our subsidiaries (except CE Electric UK and Northern Natural Gas) are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. See notes 5 and 20 to our consolidated financial statements for additional information about our 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 "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

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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.

We believe 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, MidAmerican's most significant physical properties, other than those owned by MidAmerican Energy, CE Electric UK, Kern River and Northern Natural Gas, are MidAmerican's current interests in operating power facilities and MidAmerican's plants under construction and related real property interests, as well as leases of office space for MidAmerican's residential real estate brokerage operations. See "Business" for further detail.

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REGULATION

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

General Regulation

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 our 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, or 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, or 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

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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.

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.

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.

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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 DOT pursuant to the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, which establishes safety requirements in the design, construction, operations and maintenance of interstate natural gas transmission facilities.

The FERC has jurisdiction over, among other things, the construction and operation of pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the modification or abandonment of such facilities. The FERC also has jurisdiction over the rates and charges and terms and conditions of service for the transportation of natural gas in interstate commerce. 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 PUHCA are two of the laws (including the regulations thereunder) that affect us and certain of our 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

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legislation, if adopted, could vary considerably from the terms which are presently under consideration. We believe 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 our existing QFs. We cannot provide assurance, however, that legislation, if passed, or any other similar legislation proposed in the future, would not adversely impact our existing domestic projects.

We are 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, we and each of our public utility subsidiaries from which we derive a material part of its income (currently only MidAmerican Energy) must be predominantly intrastate in character and organized in and carry on our 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 our domestic power plant operations and all of our foreign utility operations are not public utilities within the meaning of PUHCA as a result of their status as QFs under PURPA (with our ownership interest therein limited to 50%), EWGs or foreign utility companies, or are otherwise exempted from the definition of "public utility" under PUHCA. Although we believe that we will continue to qualify for exemption from additional regulation under PUHCA, it is possible that, as a result of the expansion of our public utility operations, loss of exempt status by one or more of our domestic power plants or foreign utilities, or amendments to PUHCA or the interpretation of PUHCA, we 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 us.

In the event we were unable to avoid the loss of QF status for one or more of our 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 us.

Regulatory requirements applicable in the future to nuclear generating facilities could adversely affect the results of operations of us and MidAmerican Energy, in particular. We are 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, or 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

MidAmerican's pipeline operations are subject to regulation by the DOT under the NGPSA relating to design, installation, testing, construction, operation and management of its pipeline system. The NGPSA requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain inspection and maintenance plans and to comply with such plans. MidAmerican'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

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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. We believe our 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, or 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, or 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:

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•  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, or 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,

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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, or 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 our 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 CE 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 CE 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. Our 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, we believe 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 CE Casecnan project's tariff structure and implementation. We believe 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, or 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.

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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, or 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, we are presently unable to quantify the likely impact of the proposed rule, if adopted.

Environmental Regulation

Domestic

MidAmerican'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 MidAmerican's domestic operations to obtain and comply with a wide variety of licenses, permits and other approvals. We believe that MidAmerican's 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 MidAmerican'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. We cannot assure you that existing regulations will not be revised or that new regulations will not be adopted or become applicable to MidAmerican 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, or 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, or SO2, and nitrogen oxides, or NOX, 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, NOX and mercury, as well as possible new federal regulation of carbon dioxide and other gasses that may affect global climate change.

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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 NOX 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, or 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, or 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

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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.

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.

Although the timing of potential incurred costs and recovery of such costs in rates may affect the results of operations in individual periods, we believe 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.

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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 us.

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, or 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 us.

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. We expect 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. We expect 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.

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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, or 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, or 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,

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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.

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LEGAL PROCEEDINGS

In addition to the proceedings described below, we and our subsidiaries are currently parties to various items of litigation or arbitration, none of which are reasonably expected by us to have a material adverse effect.

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., or 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 us 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. We believe 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 us 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

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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 Btu 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, or 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., or Cornerstone, was filed on August 18, 2003 in the United States District Court, Southern District of New York naming MidAmerican Energy and us. On October 1, 2003, a second complaint, Roberto, E. Calle Gracey, et al., or 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, or 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 us was entered by the court dismissing us 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. MidAmerican Energy filed a motion to dismiss on 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 "Business — CalEnergy Generation – Foreign" for additional information.

CE Casecnan Construction Contract Arbitration

The CE 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., or 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, or ICC, seeking schedule relief of up to 153 days, compensation

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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, our indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority stockholder, LaPrairie Group Contractors (International) Ltd., or LPG, that our 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 us. 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 us 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 us cannot be determined at this time.

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MANAGEMENT

Our management structure is organized functionally and our current executive officers and directors 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 our President 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 us 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 us in 1995 and served in various accounting positions including Senior Vice President and Chief Accounting Officer. Prior to joining us, 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 us in February 1993 and has served in various legal positions including General Counsel of our 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 ours since March 2000. He is Chairman of the Board and Chief Executive Officer of Berkshire Hathaway. 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 ours since June 1991. Mr. Scott was our Chairman and Chief Executive Officer from January 8, 1992 until April 19, 1993. For more than the past five years, he has been Chairman of the Board of Directors of Level 3 Communications, Inc., a successor to certain businesses of Peter Kiewit & Sons', Inc. Mr. Scott is a director of Peter Kiewit & Sons', Inc., Berkshire Hathaway, Burlington Resources, Inc., ConAgra, Inc., Valmont Industries, Inc., Kiewit Materials Co., Commonwealth Telephone Enterprises, Inc. and RCN Corporation. Mr. Scott is the father of W. David Scott.

MARC D. HAMBURG, 54, Director. Mr. Hamburg has been a director of ours since March 2000. He has served as Vice President – Chief Financial Officer of Berkshire Hathaway since October 1, 1992 and Treasurer since June 1, 1987, his date of employment with Berkshire Hathaway.

W. DAVID SCOTT, 42, Director. Mr. Scott has been a director of ours 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 ours 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 ours 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 ours since March 1991. Mr. Jaros was our President and Chief Operating Officer from January 8, 1992 to April 19, 1993 and 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 Securities Exchange Act of 1934.

Code of Ethics

We have adopted a code of ethics that applies to our principal executive officer, our principal financial officer, our chief accounting officer and certain other covered officers. The code of ethics is filed as an exhibit to our annual report on Form 10-K for the year ended December 31, 2003.

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Executive Compensation

The following table sets forth the compensation of our Chief Executive Officer and our four other most highly compensated executive officers who were employed as of December 31, 2003, which we refer to as our Named Executive Officers. Information is provided regarding our Named Executive Officers for the last three fiscal years during which they were our executive officers, if applicable.


Name and Principal Positions Year
Ended
Dec. 31		 Salary(1) Bonus(1) Other
Annual
Compensation		 All Other
Compensation (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 our Executive Split Dollar Plan for executives whose retirement benefit cannot be fully funded through our Base Retirement Plan for Salaried Employees, we have 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 us 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 our 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

We 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 our Named Executive Officers at December 31, 2003.


Name Shares
Acquired
on Exercise
(#)		 Value
Realized		 Underlying Unexercised
Option Held (#)		 Value of Unexercised
In-the-Money Options ($)(1)
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, we were acquired by a private investor group. As a privately held company, we have no publicly traded equity securities and, consequently, our 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     N/A  
Douglas L. Anderson   N/A   December 31, 2007   390,000     N/A     N/A  
Keith D. Hartje   N/A   December 31, 2007   163,913     N/A     N/A  
(1) The awards shown in the foregoing table are made pursuant to the Long-Term Incentive Partnership Plan, or 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

We maintain a Supplemental Retirement Plan for Designated Officers, which we refer 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

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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 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 our Named Executive Officers has or will have five years of credited service with us 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, we maintain life insurance on the participants in amounts expected to be sufficient to fund the after-tax cost of the projected benefits. Deferred compensation is considered part of the salary covered by the 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 we refer 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, or 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 of 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 our 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 we may terminate the employment of Mr. Sokol with cause, in which case we are 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, we are 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 us, 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 we terminate 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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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 our common stock and certain information with respect to the beneficial ownership of each director, our 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(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 MidAmerican Energy Holdings Company at 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309.
(2) Includes shares which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days.
(3) Excludes 3 million shares held by family members and family controlled trusts and corporations, the Scott Family Interests, as to which Mr. Scott disclaims beneficial ownership. Such beneficial owner's address is 1000 Kiewit Plaza, Omaha, Nebraska 68131.
(4) Includes options to purchase 1,399,277 shares of common stock that are exercisable within 60 days.
(5) Such beneficial owner's address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.
(6) Includes options to purchase 649,052 shares of common stock which are exercisable within 60 days. Excludes 10,041 shares reserved for issuance pursuant to a deferred compensation plan.
(7) Includes shares held by trusts for the benefit of or controlled by W. David Scott. Such beneficial owner's address is 11422 Miracle Hills Drive, Suite 400, Omaha, Nebraska 68154.
(8) Excludes 900,942 shares of common stock held by Berkshire Hathaway of which beneficial ownership of such shares is disclaimed.

The terms of our Zero Coupon Convertible Preferred Stock held by Berkshire Hathaway entitle the holder thereof to elect two members of our Board of Directors. The Zero Coupon Convertible Preferred Stock does not vote as to the election of any other members of our Board of Directors. Mr. Sokol's employment agreement gives him the right during the term of his employment to serve as a member of our Board of Directors and to designate two additional directors.

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Pursuant to a shareholders agreement, 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 our common stock, provided that Berkshire Hathaway is then a purchaser of a type which is able to consummate such a purchase without causing it or any of its affiliates or us or any of our 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 us.

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 MEHC's common stock subject to certain adjustments as described in MEHC's 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 MEHC 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 any merger, consolidation or sale of all or substantially all of MEHC's 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.

Certain Relationships and Related Transactions.

Under a subscription agreement with us, 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 ours which were outstanding prior to the closing of our acquisition by a private investor group on March 14, 2000 are tendered for conversion to cash by the current holders.

We provided a guarantee in favor of a third party lender in connection with a $1,663,998.75 loan from such lender to our 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 our 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 MidAmerican's acquisition of Northern Natural Gas, on August 16, 2002, we 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 our subsidiary trust, MidAmerican Capital Trust II, due August 31, 2012. The transaction was a private placement 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.

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

On January 6, 2004, we purchased shares of our 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 ours. See "—Certain Relationships and Related Transactions."

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DESCRIPTION OF THE NOTES

The original series D notes were, and the series D exchange notes will be, issued pursuant to the supplemental indenture, dated as of February 12, 2004, to the indenture, dated as of October 4, 2002 and amended as of May 16, 2003, between MidAmerican Energy Holdings Company, or MEHC, and The Bank of New York, as trustee. The term "indenture" when used in this prospectus will refer to the indenture as amended by all supplemental indentures executed and delivered on or prior to the date on which the original series D notes were issued and sold (February 12, 2004). The terms of the series D notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended.

On October 4, 2002, MEHC issued $200,000,000 of its 4.625% Senior Notes due 2007 (hereafter referred to as the series A notes) and $500,000,000 of its 5.875% Senior Notes due 2012 (hereafter referred to as the series B notes) and, on May 16, 2003, MEHC issued $450,000,000 of its 3.50% Senior notes due 2008 (hereafter referred to as the series C notes), in each case pursuant to the indenture. Unless otherwise indicated, references hereafter to the notes in this prospectus include the series A notes, the series B notes, the series C notes and the series D notes (and any other series of notes or other securities hereafter issued under a supplemental indenture or otherwise pursuant to the indenture). The term series D notes when used in the prospectus will refer to the original series D notes and the series D exchange notes.

The following description is a summary of the material provisions of the indenture and the related registration rights agreement. It does not restate those agreements in their entirety. We urge you to read the indenture and the registration rights agreement because they, and not this description, define your rights as a holder of the series D notes. The definitions of certain capitalized terms used in the following summary are set forth below under "— Definitions."

General

The indenture does not limit the aggregate principal amount of the debt securities that may be issued thereunder and provides that debt securities may be issued from time to time in one or more series.

The original series D notes were initially offered in the aggregate principal amount of $250,000,000. MEHC may, without the consent of the holders, increase such principal amount in the future on the same terms and conditions (except for the issue date and issue price) and with the same CUSIP number(s) as the series D notes.

The original series D notes were, and the series D exchange notes will be, issued in one series, bear interest at the rate of 5.00% per annum and mature on February 15, 2014. Interest on the series D notes is payable semi-annually in arrears on each February 15 and August 15, commencing August 15, 2004, to the holders thereof at the close of business on the preceding February 1 and August 1, respectively. Interest on the series D notes is computed on the basis of a 360-day year of twelve 30-day months.

The original series D notes were, and the series D exchange notes will be, issued without coupons and in fully registered form only in denominations of $1,000 and any integral multiple of $1,000.

MEHC files certain reports and other information with the SEC in accordance with the requirements of Sections 13 and 15(d) under the Exchange Act. See "Where You Can Find More Information." In addition, at any time that Sections 13 and 15(d) cease to apply to MEHC, MEHC has covenanted in the indenture to file comparable reports and information with the trustee and the SEC, and mail such reports and information to holders of notes at their registered addresses, for so long as any notes remain outstanding.

If (i) the registration statement of which this prospectus is a part is not declared effective by the SEC within 270 days after the date on which the original series D notes were issued, (ii) a shelf registration statement with respect to the resale of the series D notes is not declared effective by the SEC within 150 days after MEHC's obligation to file such shelf registration statement arises (but in

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any event not prior to 270 days after the closing date for the original series D notes) or (iii) any of the foregoing registration statements (or the prospectuses related thereto) after being declared effective by the SEC cease to be so effective or usable (subject to certain exceptions) in connection with resales of the original series D notes or the series D exchange notes for the periods specified and in accordance with the registration rights agreement, the interest rate on the series D notes that are then subject to such cessation or other registration default will increase by 0.5% from and including the date on which any such event occurs until such event ceases to be continuing. The registration rights are more fully described under "Exchange Offer — Liquidated Damages."

Any original series D notes that remain outstanding after the consummation of the exchange offer, together with all series D exchange notes issued in connection with the exchange offer, will be treated as a single class of securities under the indenture.

Optional Redemption

General

The series D notes are redeemable in whole or in part, at the option of MEHC at any time, at a redemption price equal to the greater of:

(1)  100% of the principal amount of the series D notes being redeemed; or
(2)  the sum of the present values of the remaining scheduled payments of principal of and interest on the series D notes being redeemed discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at a discount rate equal to the Treasury Yield plus 20 basis points,

plus, for (1) or (2) above, whichever is applicable, accrued interest on such series D notes to the date of redemption.

Notice of redemption shall be given not less than 30 days nor more than 60 days prior to the date of redemption. If fewer than all the series D notes are to be redeemed, selection of series D notes for redemption will be made by the trustee in any manner the trustee deems fair and appropriate.

Unless MEHC defaults in payment of the Redemption Price (as defined below), from and after the date of redemption the series D notes or portions of series D notes called for redemption will cease to bear interest, and the holders of those series D notes will have no right in respect of those series D notes except the right to receive the applicable Redemption Price.

Optional Redemption Provisions

Under the procedures described above, the price payable upon the optional redemption at any time of a series D note (the "Redemption Price") is determined by calculating the present value (the "Present Value") at such time of each remaining payment of principal of or interest on such series D note and then totaling those Present Values. If the sum of those Present Values is equal to or less than 100% of the principal amount of such series D note, the Redemption Price of such series D note will be 100% of its principal amount (redemption at par). If the sum of those Present Values is greater than 100% of the principal amount of such series D note, the Redemption Price of such series D note will be such greater amount (redemption at a premium). In no event may a series D note be redeemed optionally at less than 100% of its principal amount.

The Present Value at any time of a payment of principal of or interest on a series D note is calculated by applying to such payment the discount rate (the "Discount Rate") applicable to such payment. The Discount Rate applicable at any time to payment of principal of or interest on a series D note equals the equivalent yield to maturity at such time of a fixed rate United States treasury security having a maturity comparable to the maturity of such payment plus 20 basis points, such yield being calculated on the basis of the interest rate borne by such United States treasury security and the price at such time of such security. The United States treasury security employed in the calculation of a Discount Rate (a "Relevant Security") as well as the price and equivalent yield to maturity of such Relevant Security will be selected or determined by an Independent Investment Banker.

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Whether the sum of the Present Values of the remaining payments of principal of and interest on a series D note to be redeemed optionally will or will not exceed 100% of its principal amount and, accordingly, whether such series D note will be redeemed at par or at a premium will depend on the Discount Rate used to calculate such Present Values. Such Discount Rate, in turn, will depend upon the equivalent yield to maturity of a Relevant Security, which yield will itself depend on the interest rate borne by, and the price of, the Relevant Security. While the interest rate borne by the Relevant Security is fixed, the price of the Relevant Security tends to vary with interest rate levels prevailing from time to time. In general, if at a particular time the prevailing level of interest rates for a newly issued United States treasury security having a maturity comparable to that of a Relevant Security is higher than the level of interest rates for newly issued United States treasury securities having a maturity comparable to such Relevant Security prevailing at the time the Relevant Security was issued, the price of the Relevant Security will be lower than its issue price. Conversely, if at a particular time the prevailing level of interest rates for a newly issued United States treasury security having a maturity comparable to that of a Relevant Security is lower than the level of interest rates prevailing for newly issued United States treasury securities having a maturity comparable to the Relevant Security at the time the Relevant Security was issued, the price of the Relevant Security will be higher than its issue price.

Because the equivalent yield to maturity on a Relevant Security depends on the interest rate it bears and its price, an increase or a decrease in the level of interest rates for newly issued United States treasury securities with a maturity comparable to that of a Relevant Security above or below the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Relevant Security prevailing at the time of issue of the Relevant Security will generally result in an increase or a decrease, respectively, in the Discount Rate used to determine the Present Value of a payment of principal of or interest on a series D note. An increase or a decrease in the Discount Rate, and therefore an increase or a decrease in the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Relevant Security, will result in a decrease or an increase, respectively, of the Present Value of a payment of principal of or interest on a series D note. In other words, the Redemption Price varies inversely with the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Comparable Treasury Issue. As noted above, however, if the sum of the Present Values of the remaining payments of principal of and interest on a series D note proposed to be redeemed is less than its principal amount, such series D note may only be redeemed at par.

Sinking Fund

The series D notes are not subject to any mandatory sinking fund.

Ranking

The series D notes are general, unsecured senior obligations of MEHC and rank pari passu in right of payment with all other existing and future senior unsecured obligations of MEHC (including the series A notes, series B notes and series C notes) and senior in right of payment to all existing and future subordinated obligations of MEHC. The series D notes are effectively subordinated to all existing and future secured obligations of MEHC and to all existing and future obligations of MEHC's Subsidiaries. At December 31, 2003, MEHC's outstanding senior indebtedness was approximately $2.8 billion and MEHC's outstanding subordinated indebtedness was approximately $1.9 billion. These amounts exclude MEHC's Salton Sea Guarantee, which was effectively terminated on March 1, 2004 through the use of a portion of the proceeds from the offering of the original series D notes. These amounts further exclude MEHC's other guarantees and letters of credit in respect of Subsidiary and equity investment indebtedness aggregating approximately $124.1 million as of December 31, 2003. MEHC's Subsidiaries also have significant amounts of indebtedness. At December 31, 2003, MEHC's consolidated Subsidiaries had outstanding indebtedness totaling approximately $7.2 billion (which includes the $136.4 million aggregate principal amount of Salton Sea Series F Bonds redeemed on March 1, 2004 through the use of a portion of the proceeds from the offering of the original series D notes). This amount does not include (i) any trade debt or preferred stock obligations of MEHC's

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Subsidiaries, (ii) MEHC's Subsidiaries' letters of credit in respect of their indebtedness, or (iii) MEHC's share of the outstanding indebtedness of its and its Subsidiaries' equity investments.

Covenants

Except as set forth under "— Defeasance and Discharge" below, for so long as any notes remain outstanding, MEHC will comply with the terms of the covenants set forth below.

Restrictions On Liens

MEHC is not permitted to pledge, mortgage, hypothecate or permit to exist any pledge, mortgage or other Lien upon any property or assets at any time directly owned by MEHC to secure any indebtedness for money borrowed which is incurred, issued, assumed or guaranteed by MEHC ("Indebtedness for Borrowed Money"), without making effective provisions whereby the outstanding notes will be equally and ratably secured with any and all such Indebtedness for Borrowed Money and with any other Indebtedness for Borrowed Money similarly entitled to be equally and ratably secured; provided however, that this restriction will not apply to or prevent the creation or existence of:

(1)  any Liens existing prior to the issuance of the notes;
(2)  purchase money Liens which do not exceed the cost or value of the purchased property or assets;
(3)  any Liens not to exceed 10% of Consolidated Net Tangible Assets; and
(4)  any Liens on property or assets granted in connection with extending, renewing, replacing or refinancing in whole or in part the Indebtedness for Borrowed Money (including, without limitation, increasing the principal amount of such Indebtedness for Borrowed Money) secured by Liens described in the foregoing clauses (1) through (3), provided that the Liens in connection with any such extension, renewal, replacement or refinancing will be limited to the specific property or assets that was subject to the original Lien.

In the event that MEHC proposes to pledge, mortgage or hypothecate or permit to exist any pledge, mortgage or other Lien upon any property or assets at any time directly owned by it to secure any Indebtedness for Borrowed Money, other than as permitted by clauses (1) through (4) of the previous paragraph, MEHC will give prior written notice thereof to the trustee and MEHC will, prior to or simultaneously with such pledge, mortgage or hypothecation, effectively secure all the notes equally and ratably with such Indebtedness for Borrowed Money.

The foregoing covenant will not restrict the ability of MEHC's Subsidiaries and affiliates to pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or Lien upon their property or assets, in connection with project financings or otherwise.

Consolidation, Merger, Conveyance, Sale or Lease

MEHC is not permitted to consolidate with or merge with or into any other person, or convey, transfer or lease its consolidated properties and assets substantially as an entirety to any person, or permit any person to merge into or consolidate with MEHC, unless (1) MEHC is the surviving or continuing corporation or the surviving or continuing corporation or purchaser or lessee is a corporation incorporated under the laws of the United States of America, one of the States thereof or the District of Columbia or Canada and assumes MEHC's obligations under the notes and under the indenture and (2) immediately before and after such transaction, no event of default under the indenture shall have occurred and be continuing.

Except for a sale of the consolidated properties and assets of MEHC substantially as an entirety as provided above, and other than properties or assets required to be sold to conform with laws or governmental regulations, MEHC is not permitted, directly or indirectly, to sell or otherwise dispose of any of its consolidated properties or assets (other than short-term, readily marketable investments purchased for cash management purposes with funds not representing the proceeds of other asset sales) if on a pro forma basis, the aggregate net book value of all such sales during the most recent

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12-month period would exceed 10% of Consolidated Net Tangible Assets computed as of the end of the most recent quarter preceding such sale; provided, however, that (1) any such sales shall be disregarded for purposes of this 10% limitation if the net proceeds are invested in properties or assets in similar or related lines of business of MEHC and its Subsidiaries, including, without limitation, any of the lines of business in which MEHC or any of its Subsidiaries is engaged on the date of such sale or disposition, and (2) MEHC may sell or otherwise dispose of consolidated properties and assets in excess of such 10% limitation if the net proceeds from such sales or dispositions, which are not reinvested as provided above, are retained by MEHC as cash or Cash Equivalents or used to retire Indebtedness for Borrowed Money of MEHC (other than Indebtedness for Borrowed Money which is subordinated to the notes) and its Subsidiaries.

Purchase of Notes Upon a Change of Control

Upon the occurrence of a Change of Control, each holder of the notes will have the right to require that MEHC repurchase all or any part of such holder's notes at a purchase price in cash equal to 101% of the principal thereof on the date of purchase plus accrued interest, if any, to the date of purchase.

The Change of Control provisions may not be waived by the trustee or by the board of directors of MEHC, and any modification thereof must be approved by each holder. Nevertheless, the Change of Control provisions will not necessarily afford protection to holders, including protection against an adverse effect on the value of the notes of any series, in the event that MEHC or its Subsidiaries incur additional Debt, whether through recapitalizations or otherwise.

Within 30 days following a Change of Control, MEHC will mail a notice to each holder of the notes with a copy to the trustee, stating the following:

(1)  that a Change of Control has occurred and that such holder has the right to require MEHC to purchase such holder's notes at the purchase price described above (the "Change of Control Offer");
(2)  the circumstances and relevant facts regarding such Change of Control (including information with respect to pro forma historical income, cash flow and capitalization after giving effect to such Change of Control);
(3)  the purchase date (which will be not earlier than 30 days nor later than 60 days from the date such notice is mailed) (the "Purchase Date");
(4)  that after the Purchase Date interest on such note will continue to accrue (except as provided in clause (5));
(5)  that any note properly tendered pursuant to the Change of Control Offer will cease to accrue interest after the Purchase Date (assuming sufficient moneys for the purchase thereof are deposited with the trustee);
(6)  that holders electing to have a note purchased pursuant to a Change of Control Offer will be required to surrender the note, with the form entitled "Option of Holder To Elect Purchase" on the reverse of the note completed, to the paying agent at the address specified in the notice prior to the close of business on the fifth business day prior to the Purchase Date;
(7)  that a holder will be entitled to withdraw such holder's election if the paying agent receives, not later than the close of business on the third business day (or such shorter periods as may be required by applicable law) preceding the Purchase Date, a telegram, telex, facsimile transmission or letter setting forth the name of the holder, the principal amount of notes the holder delivered for purchase, and a statement that such holder is withdrawing his election to have such notes of such series purchased; and
(8)  that holders that elect to have their notes purchased only in part will be issued new notes having a principal amount equal to the portion of the notes that were surrendered but not tendered and purchased.

On the Purchase Date, MEHC will (1) accept for payment all notes or portions thereof tendered pursuant to the Change of Control Offer, (2) deposit with the trustee money sufficient to pay the

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purchase price of all notes or portions thereof so tendered for purchase and (3) deliver or cause to be delivered to the trustee the notes properly tendered together with an officer's certificate identifying the notes or portions thereof tendered to MEHC for purchase. The trustee will promptly mail, to the holders of the notes properly tendered and purchased, payment in an amount equal to the purchase price, and promptly authenticate and mail to each holder a new note having a principal amount equal to any portion of such holder's notes that were surrendered but not tendered and purchased. MEHC will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Purchase Date.

If MEHC is prohibited by applicable law from making the Change of Control Offer or purchasing notes of any series thereunder, MEHC need not make a Change of Control Offer pursuant to this covenant for so long as such prohibition is in effect.

MEHC will comply with all applicable tender offer rules, including, without limitation, Rule 14e-1 under the Exchange Act, in connection with a Change of Control Offer.

Events of Default

An event of default with respect to the notes of any series will be defined in the indenture as being any one of the following events:

(1)  default as to the payment of interest on any note of that series for 30 days after payment is due;
(2)  default as to the payment of principal of, or premium, if any, on any note of that series or as to any payment required in connection with a Change of Control;
(3)  failure to make a Change of Control Offer required under the covenants described under "Purchase of Notes Upon a Change of Control" above or a failure to purchase the notes of that series tendered in respect of such Change of Control Offer;
(4)  default in the performance, or breach, of any covenant, agreement or warranty of MEHC contained in the indenture and the notes of that series and such failure continues for 30 days after written notice is given to MEHC by the trustee or to MEHC and the trustee by the holders of at least a majority in aggregate principal amount outstanding of the notes of that series, as provided in the indenture;
(5)  default on any other Debt of MEHC or any Significant Subsidiary (other than Debt that is Non-Recourse to MEHC) if either (x) such default results from failure to pay principal of such Debt in excess of $100 million when due after any applicable grace period or (y) as a result of such default, the maturity of such Debt has been accelerated prior to its scheduled maturity and such default has not been cured within the applicable grace period, and such acceleration has not been rescinded, and the principal amount of such Debt, together with the principal amount of any other Debt of MEHC and its Significant Subsidiaries (not including Debt that is Non-Recourse to MEHC) that is in default as to principal, or the maturity of which has been accelerated, aggregates $100 million or more;
(6)  the entry by a court of one or more judgments or orders against MEHC or any Significant Subsidiary for the payment of money that in the aggregate exceeds $100 million (excluding (i) the amount thereof covered by insurance or by a bond written by a person other than an affiliate of MEHC (other than, with respect to, among others, the series D notes, Berkshire Hathaway or any of its affiliates that provide commercial insurance in the ordinary course of their business) and (ii) judgments that are Non-Recourse to MEHC), which judgments or orders have not been vacated, discharged or satisfied or stayed pending appeal within 60 days from the entry thereof, provided that such a judgment or order will not be an event of default if such judgment or order does not require any payment by MEHC; and
(7)  certain events involving bankruptcy, insolvency or reorganization of MEHC or any of its Significant Subsidiaries.

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The indenture provides that the trustee may withhold notice to the holders of any default (except in payment of principal of, premium, if any, or interest on any series of notes and any payment required in connection with a Change of Control) if the trustee considers it in the interest of holders to do so.

The indenture provides that if an event of default with respect to the notes of any series at the time outstanding (other than an event of bankruptcy, insolvency or reorganization of MEHC or a Significant Subsidiary) has occurred and is continuing, either the trustee or (i) in the case of any event of default described in clause (1) or (2) above, the holders of at least 33% in aggregate principal amount of the notes of that series then outstanding, or (ii) in the case of any other event of default, the holders of at least a majority in aggregate principal amount of the notes of that series then outstanding, may declare the principal of and any accrued interest on all notes of that series to be due and payable immediately, but upon certain conditions such declaration may be annulled and past defaults (except, unless theretofore cured, a default in payment of principal of, premium, if any, or interest on the notes of that series or any payment required in connection with a Change of Control) may be waived by the holders of a majority in principal amount of the notes of that series then outstanding. If an event of default due to the bankruptcy, insolvency or reorganization of MEHC or a Significant Subsidiary occurs, the indenture provides that the principal of and interest on all notes will become immediately due and payable without any action by the trustee, the holders of notes or any other person.

The holders of a majority in principal amount of the notes of any series then outstanding will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee under the indenture with respect to the notes of such series, subject to certain limitations specified in the indenture, provided that the holders of notes of such series must have offered to the trustee reasonable indemnity against expenses and liabilities.

The indenture requires the annual filing by MEHC with the trustee of a written statement as to its knowledge of the existence of any default in the performance and observance of any of the covenants contained in the indenture.

Modification of the Indenture

The indenture contains provisions permitting MEHC and the trustee, with the consent of the holders of not less than a majority in principal amount of the outstanding notes of each series affected by the modification, to modify the indenture or the rights of the holders of such series, except that no such modification may (1) extend the stated maturity of the principal of or any installment of interest on the notes, reduce the principal amount thereof or the interest rate thereon, reduce any premium payable on redemption or purchase thereof, impair the right of any holder to institute suit for the enforcement of any such payment on or after the stated maturity thereof or make any change in the covenants regarding a Change of Control or the related definitions without the consent of the holder of each outstanding note so affected, or (2) reduce the percentage of any series of notes, the consent of the holders of which is required for any such modification, without the consent of the holders of all series of notes then outstanding.

Defeasance and Discharge

Legal Defeasance

The indenture provides that MEHC will be deemed to have paid and will be discharged from any and all obligations in respect of the notes of any series on the 123rd day after the deposit referred to below has been made (or immediately if an opinion of counsel is delivered to the effect described in clause (B)(3)(y) below), and the provisions of the indenture will cease to be applicable with respect to the notes of such series (except for, among other matters, certain obligations to register the transfer or exchange of the notes of such series, to replace stolen, lost or mutilated notes of such series, to maintain paying agents and to hold monies for payment in trust) if, among other things:

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(A)  MEHC has deposited with the trustee, in trust, money and/or U.S. Government Obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide money in an amount sufficient to pay the principal of, premium, if any, and accrued and unpaid interest on the applicable notes, on the respective stated maturities of the notes or, if MEHC makes arrangements satisfactory to the trustee for the redemption of the notes prior to their stated maturity, on any earlier redemption date in accordance with the terms of the indenture and the applicable notes;
(B)  MEHC has delivered to the trustee:
(1)  either (x) an opinion of counsel to the effect that holders will not recognize income, gain or loss for federal income tax purposes as a result of such deposit, defeasance and discharge and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge had not occurred and MEHC had paid or redeemed such notes on the applicable dates, which opinion of counsel must be based upon a ruling of the Internal Revenue Service to the same effect or a change in applicable federal income tax law or related Treasury regulations after the date of the indenture, or (y) a ruling directed to the trustee or MEHC received from the Internal Revenue Service to the same effect as the aforementioned opinion of counsel;
(2)  an opinion of counsel to the effect that the creation of the defeasance trust does not violate the Investment Company Act of 1940; and
(3)  an opinion of counsel to the effect that either (x) after the passage of 123 days following the deposit referred to in clause (A) above, the trust fund will not be subject to the effect of Section 547 or 548 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law or (y) based upon existing precedents, if the matter were properly briefed, a court should hold that the deposit of moneys and/or U.S. Government Obligations as provided in clause (A) above would not constitute a preference voidable under Section 547 or 548 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law;
(C)  immediately after giving effect to such deposit referred to in clause (A) above on a pro forma basis, no event of default under the indenture, or event that after the giving of notice or lapse of time or both would become an event of default, will have occurred and be continuing on the date of such deposit or (unless an opinion of counsel is delivered to the effect described in clause (B)(3)(y) above) during the period ending on the 123rd day after the date of such deposit, and such deposit and discharge will not result in a breach or violation of, or constitute a default under, any other material agreement or instrument to which MEHC is a party or by which MEHC is bound; and
(D)  if at such time the notes are listed on a national securities exchange, MEHC has delivered to the trustee an opinion of counsel to the effect that the notes will not be delisted as a result of such deposit, defeasance and discharge.

Covenant Defeasance

The indenture further provides that the provisions of the covenants described herein under "Covenants — Restrictions on Liens", "— Consolidation, Merger, Conveyance, Sale or Lease" and "— Purchase of Notes Upon a Change of Control," clauses (3) and (4) under "Events of Default" with respect to such covenants, clause (2) under "Events of Default" with respect to offers to purchase upon a Change of Control as described above and clauses (5) and (6) under "Events of Default" will cease to be applicable to MEHC and its Subsidiaries upon the satisfaction of the provisions described in clauses (A), (B), (C) and (D) of the preceding paragraph; provided, however, that with respect to such covenant defeasance, the opinion of counsel described in clause (B)(1)(x) above need not be based upon any ruling of the Internal Revenue Service or change in applicable federal income tax law or related Treasury regulations.

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Defeasance and Certain Other Events of Default

If MEHC exercises its option to omit compliance with certain covenants and provisions of the indenture with respect to the notes of any series as described in the immediately preceding paragraph and any series of notes is declared due and payable because of the occurrence of an event of default that remains applicable, the amount of money and/or U.S. Government Obligations on deposit with the trustee will be sufficient to pay amounts due on such notes at the time of their stated maturity or scheduled redemption, but may not be sufficient to pay amounts due on such notes at the time of acceleration resulting from such event of default. MEHC will remain liable for such payments.

Governing Law

The indenture and the notes are governed by, and construed in accordance with, the law of the State of New York, including Section 5-1401 of the New York General Obligations Law, but otherwise without regard to conflict of laws rules.

Trustee

The Bank of New York is the trustee under the indenture. The Bank of New York (or one of its affiliates) currently serves, and may in the future serve, as trustee under indentures evidencing other indebtedness of MEHC and its affiliates. The Bank of New York (or one of its affiliates) is also, and may in the future be, a lender under credit facilities for MEHC and its affiliates.

Definitions

Set forth below is a summary of certain of the defined terms used in the covenants and other provisions of the indenture. Reference is made to the indenture for the full definitions of all such terms as well as any other capitalized terms used herein for which no definition is provided.

"Attributable Value" means, as to a Capitalized Lease Obligation under which any person is at the time liable and at any date as of which the amount thereof is to be determined, the capitalized amount thereof that would appear on the face of a balance sheet of such person in accordance with GAAP.

"Berkshire Hathaway" means Berkshire Hathaway Inc. and any Subsidiary of Berkshire Hathaway Inc.

"Capital Stock" means, with respect to any person, any and all shares, interests, participations or other equivalents (however designated, whether voting or non-voting) in, or interests (however designated) in, the equity of such person that is outstanding or issued on or after the date of the indenture, including, without limitation, all common stock and preferred stock and partnership and joint venture interests in such person.

"Capitalized Lease" means, as applied to any person, any lease of any property of which the discounted present value of the rental obligations of such person as lessee, in conformity with GAAP, is required to be capitalized on the balance sheet of such person, and "Capitalized Lease Obligation" means the rental obligations, as aforesaid, under such lease.

"Cash Equivalent" means any of the following:

(1)  securities issued or directly and fully guaranteed or insured by the United States of America or any agency or instrumentality thereof (provided that the full faith and credit of the United States of America is pledged in support thereof);
(2)  time deposits and certificates of deposit of any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000 with a maturity date not more than two years from the date of acquisition;

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(3)  repurchase obligations with a term of not more than 30 days for underlying securities of the types described in clauses (1) or (5) of this definition that were entered into with any bank meeting the qualifications set forth in clause (2) of this definition or another financial institution of national reputation;
(4)  direct obligations issued by any state or other jurisdiction of the United States of America or any other country or any political subdivision or public instrumentality thereof maturing, or subject to tender at the option of the holder thereof, within 90 days after the date of acquisition thereof and, at the time of acquisition, having a rating of at least A from S&P or A-2 from Moody's (or, if at any time neither S&P nor Moody's may be rating such obligations, then from another nationally recognized rating service acceptable to the trustee);
(5)  commercial paper issued by (a) the parent corporation of any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000, and (b) others having one of the two highest ratings obtainable from either S&P or Moody's (or, if at any time neither S&P nor Moody's may be rating such obligations, then from another nationally recognized rating service acceptable to the trustee) and in each case maturing within one year after the date of acquisition;
(6)  overnight bank deposits and bankers' acceptances at any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000;
(7)  deposits available for withdrawal on demand with any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000;
(8)  investments in money market funds substantially all of whose assets comprise securities of the types described in clauses (1) through (6) and (9) of this definition; and
(9)  auction rate securities or money market preferred stock having one of the two highest ratings obtainable from either S&P or Moody's (or, if at any time neither S&P nor Moody's may be rating such obligations, then from another nationally recognized rating service acceptable to the trustee).

"Change of Control" means the occurrence of one or more of the following events:

(1)  a transaction pursuant to which Berkshire Hathaway ceases to own, on a diluted basis (assuming conversion of all of MEHC's convertible preferred stock and any other Capital Stock of MEHC that is issued and outstanding, regardless of whether any such convertible preferred stock or other Capital Stock is then presently convertible), at least a majority of the issued and outstanding common stock of MEHC; or
(2)  MEHC or its Subsidiaries sell, convey, assign, transfer, lease or otherwise dispose of all or substantially all the property of MEHC and its Subsidiaries taken as a whole to any person or entity other than an entity at least a majority of the issued and outstanding common stock of which is owned by Berkshire Hathaway, calculated on a diluted basis as described above;

provided that with respect to the foregoing subparagraphs (1) and (2), a Change of Control will not be deemed to have occurred unless and until a Rating Decline has occurred as well.

"Comparable Treasury Issue" means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of notes of any series to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes.

"Comparable Treasury Price" means, with respect to any Redemption Date, (1) the average of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) on the third business day preceding such Redemption Date, as set forth in the

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daily statistical release (or any successor release) published by the Federal Reserve Bank of New York and designated "Composite 3:30 p.m. Quotations for U.S. Government Securities" or (2) if such release (or any successor release) is not published or does not contain such prices on such business day, the Reference Treasury Dealer Quotation for such Redemption Date.

"Consolidated Net Tangible Assets" means, as of the date of any determination thereof, the total amount of all assets of MEHC determined on a consolidated basis in accordance with GAAP as of such date less the sum of (a) the consolidated current liabilities of MEHC determined in accordance with GAAP and (b) assets properly classified as Intangible Assets.

"Currency Protection Agreement" means, with respect to any person, any foreign exchange contract, currency swap agreement or other similar agreement or arrangement intended to protect such person against fluctuations in currency values to or under which such person is a party or a beneficiary on the date of the indenture or becomes a party or a beneficiary thereafter.

"Debt" means, with respect to any person, at any date of determination (without duplication):

(1)  all Indebtedness for Borrowed Money of such person;
(2)  all obligations of such person evidenced by bonds, debentures, notes or other similar instruments;
(3)  all obligations of such person in respect of letters of credit, bankers' acceptances, surety, bid, operating and performance bonds, performance guarantees or other similar instruments or obligations (or reimbursement obligations with respect thereto) (except, in each case, to the extent incurred in the ordinary course of business);
(4)  all obligations of such person to pay the deferred purchase price of property or services, except Trade Payables;
(5)  the Attributable Value of all obligations of such person as lessee under Capitalized Leases;
(6)  all Debt of others secured by a Lien on any Property of such person, whether or not such Debt is assumed by such person, provided that, for purposes of determining the amount of any Debt of the type described in this clause, if recourse with respect to such Debt is limited to such Property, the amount of such Debt will be limited to the lesser of the fair market value of such Property or the amount of such Debt;
(7)  all Debt of others Guaranteed by such person to the extent such Debt is Guaranteed by such person;
(8)  all Redeemable Stock valued at the greater of its voluntary or involuntary liquidation preference plus accrued and unpaid dividends; and
(9)  to the extent not otherwise included in this definition, all net obligations of such person under Currency Protection Agreements and Interest Rate Protection Agreements.

For purposes of determining any particular amount of Debt that is or would be outstanding, Guarantees of, or obligations with respect to letters of credit or similar instruments supporting (to the extent the foregoing constitutes Debt), Debt otherwise included in the determination of such particular amount will not be included. For purposes of determining compliance with the indenture, in the event that an item of Debt meets the criteria of more than one of the types of Debt described in the above clauses, MEHC, in its sole discretion, will classify such item of Debt and only be required to include the amount and type of such Debt in one of such clauses.

"Guarantee" means any obligation, contingent or otherwise, of any person directly or indirectly guaranteeing any Debt of any other person and, without limiting the generality of the foregoing, any Debt obligation, direct or indirect, contingent or otherwise, of such person (1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Debt of such other person (whether arising by virtue of partnership arrangements (other than solely by reason of being a general partner of a partnership), or by agreement to keep-well, to purchase assets, goods, securities or services or to take-or-pay, or to maintain financial statement conditions or otherwise) or (2) entered into for

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purposes of assuring in any other manner the obligee of such Debt of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part), provided that the term "Guarantee" will not include endorsements for collection or deposit in the ordinary course of business or the grant of a lien in connection with any Non-Recourse Debt. The term "Guarantee" used as a verb has a corresponding meaning.

"Independent Investment Banker" means an independent investment banking institution of international standing appointed by MEHC.

"Intangible Assets" means, as of the date of determination thereof, all assets of MEHC properly classified as intangible assets determined on a consolidated basis in accordance with GAAP. "Interest Rate Protection Agreement" means, with respect to any person, any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement intended to protect such person against fluctuations in interest rates to or under which such person or any of its Subsidiaries is a party or a beneficiary on the date of the indenture or becomes a party or a beneficiary thereafter.

"Investment Grade" means with respect to the notes, (1) in the case of S&P, a rating of at least BBB–, (2) in the case of Moody's, a rating of at least Baa3, and (3) in the case of a Rating Agency other than S&P or Moody's, the equivalent rating, or in each case, any successor, replacement or equivalent definition as promulgated by S&P, Moody's or other Rating Agency as the case may be.

"Joint Venture" means a joint venture, partnership or other similar arrangement, whether in corporate, partnership or other legal form.

"Lien" means, with respect to any Property, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such Property, but will not include any partnership, joint venture, shareholder, voting trust or similar governance agreement with respect to Capital Stock in a Subsidiary or Joint Venture. For purposes of the indenture, MEHC will be deemed to own subject to a Lien any Property that it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such Property.

"Non-Recourse" means any Debt or other obligation (or that portion of such Debt or other obligation) that is without recourse to MEHC or any property or assets directly owned by MEHC (other than a pledge of the equity interests in any Subsidiary of MEHC, to the extent recourse to MEHC under such pledge is limited to such equity interests).

"Property" of any person means all types of real, personal, tangible or mixed property owned by such person whether or not included in the most recent consolidated balance sheet of such person under GAAP.

"Rating Agencies" means (1) S&P and (2) Moody's or (3) if S&P or Moody's or both do not make a rating of the notes publicly available, a nationally recognized securities rating agency or agencies, as the case may be, selected by MEHC, which will be substituted for S&P, Moody's or both, as the case may be.

"Rating Category" means (1) with respect to S&P, any of the following categories: BB, B, CCC, CC, C and D (or equivalent successor categories), (2) with respect to Moody's, any of the following categories: Ba, B, Caa, Ca, C and D (or equivalent successor categories) and (3) the equivalent of any such category of S&P or Moody's used by another Rating Agency. In determining whether the rating of the notes has decreased by one or more gradations, gradations within Rating Categories (+ and – for S&P, 1, 2 and 3 for Moody's or the equivalent gradations for another Rating Agency) will be taken into account (e.g., with respect to S&P, a decline in a rating from BB+ to BB, as well as from BB– to B+, will constitute a decrease of one gradation).

"Rating Decline" means the occurrence of the following on, or within 90 days after, the earlier of (1) the occurrence of a Change of Control and (2) the date of public notice of the occurrence of a Change of Control or of the public notice of the intention of MEHC to effect a Change of Control

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(the "Rating Date"), which period will be extended so long as the rating of the notes is under publicly announced consideration for possible downgrading by any of the Rating Agencies: (a) in the event that any series of the notes are rated by either Rating Agency on the Rating Date as Investment Grade, the rating of such notes by both such Rating Agencies is reduced below Investment Grade, or (b) in the event the notes are rated below Investment Grade by both such Rating Agencies on the Rating Date, the rating of such notes by either Rating Agency is decreased by one or more gradations (including gradations within Rating Categories as well as between Rating Categories).

"Redeemable Stock" means any class or series of Capital Stock of any person that by its terms or otherwise is (1) required to be redeemed prior to the stated maturity of any series of the notes, (2) redeemable at the option of the holder of such class or series of Capital Stock at any time prior to the stated maturity of any series of the notes or (3) convertible into or exchangeable for Capital Stock referred to in clause (1) or (2) above or Debt having a scheduled maturity prior to the stated maturity of any series of the notes, provided that any Capital Stock that would not constitute Redeemable Stock but for provisions thereof giving holders thereof the right to require MEHC to purchase or redeem such Capital Stock upon the occurrence of a "change of control" occurring prior to the stated maturity of any series of the notes will not constitute Redeemable Stock if the "change of control" provisions applicable to such Capital Stock are no more favorable to the holders of such Capital Stock than the provisions contained in the covenants described under "Purchase of Notes Upon a Change of Control" above.

"Redemption Date" means any date on which MEHC redeems all or any portion of the notes in accordance with the terms of the indenture.

"Reference Treasury Dealer" means a primary U.S. government securities dealer in New York City appointed by MEHC.

"Reference Treasury Dealer Quotation" means, with respect to the Reference Treasury Dealer and any Redemption Date, the average, as determined by MEHC, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount and quoted in writing to MEHC by such Reference Treasury Dealer at 5:00 p.m. on the third business day preceding such Redemption Date).

"Significant Subsidiary" means a "significant subsidiary" as defined in Rule 1-02(w) of Regulation S-X under the Securities Act and the Exchange Act, substituting 20 percent for 10 percent each place it appears therein. Unless the context otherwise clearly requires, any reference to a "Significant Subsidiary" is a reference to a Significant Subsidiary of MEHC.

"Subsidiary" means, with respect to any person, including, without limitation, MEHC and its Subsidiaries, any corporation or other entity of which such person owns, directly or indirectly, a majority of the Capital Stock or other ownership interests and has ordinary voting power to elect a majority of the board of directors or other persons performing similar functions.

"Trade Payables" means, with respect to any person, any accounts payable or any other indebtedness or monetary obligation to trade creditors incurred, created, assumed or Guaranteed by such person or any of its Subsidiaries or Joint Ventures arising in the ordinary course of business.

"Treasury Yield" means, with respect to any Redemption Date, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such Redemption Date.

"U.S. Government Obligations" means any securities that are (1) direct obligations of the United States for the payment of which its full faith and credit is pledged or (2) obligations of a person controlled or supervised by and acting as an agency or instrumentality of the United States, the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States, that, in either case are not callable or redeemable at the option of the issuer thereof, and will also include any depository receipt issued by a bank or trust company as custodian with respect to any such U.S. Government Obligations or a specific payment of interest on or principal of any such U.S.

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Government Obligation held by such custodian for the account of the holder of a depository receipt, provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depository receipt.

"Voting Stock" means, with respect to any person, Capital Stock of any class or kind ordinarily having the power to vote for the election of directors (or persons fulfilling similar responsibilities) of such person.

Global Notes; Book-Entry System

The original series D notes were, and the series D exchange notes will be, issued under a book-entry system in the form of one or more global notes (each, a "Global Note"). Each Global Note with respect to the original series D notes was, and each Global Note with respect to the series D exchange notes will be, deposited with, or on behalf of, a depositary, which is The Depository Trust Company, New York, New York (the "Depositary"). The Global Notes with respect to the original series D notes were, and the Global Notes with respect to the series D exchange notes will be, registered in the name of the Depositary or its nominee.

The original series D notes were not issued in certificated form and, except under the limited circumstances described below, owners of beneficial interests in the Global Notes are not entitled to physical delivery of the series D notes in certificated form. The Global Notes may not be transferred except as a whole by the Depositary to a nominee of the Depositary or by a nominee of the Depositary to the Depositary or another nominee of the Depositary or by the Depositary or any nominee to a successor of the Depositary or a nominee of such successor.

The Depositary is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code, and a "clearing agency" registered pursuant to the provisions of Section 17A of the Exchange Act. The Depositary holds securities that its participants ("Direct Participants") deposit with the Depositary. The Depositary also facilitates the post-trade settlement among Direct Participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in Direct Participants' accounts, thereby eliminating the need for physical movement of securities certificates. Direct Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations, including Euroclear Bank S.A./N.V. as operator of the Euroclear System ("Euroclear") and Clearstream Banking, société anonyme ("Clearstream"). The Depositary is a wholly owned subsidiary of The Depository Trust & Clearing Corporation ("DTCC"). DTCC, in turn, is owned by a number of Direct Participants and Members of the National Securities Clearing Corporation, Government Securities Clearing Corporation, MBS Clearing Corporation and Emerging Markets Clearing Corporation, also subsidiaries of DTCC, as well as by the New York Stock Exchange, Inc., the American Stock Exchange LLC and the National Association of Securities Dealers, Inc. Access to the Depositary system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly ("Indirect Participants"). The rules applicable to the Depositary and its Direct and Indirect Participants are on file with the SEC.

Purchases of the notes under the Depositary system must be made by or through Direct Participants, which will receive a credit for the notes on the Depositary's records. The ownership interest of each actual purchaser of each note ("Beneficial Owner") is in turn to be recorded on the Direct and Indirect Participants' records. Beneficial Owners will not receive written confirmation from the Depositary of their purchase, but Beneficial Owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the notes are to be accomplished by entries made on the books of Direct and

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Indirect Participants acting on behalf of Beneficial Owners. Beneficial Owners will not receive certificates representing their ownership interests in notes, except in the event that use of the book-entry system for the notes is discontinued.

To facilitate subsequent transfers, all series D notes deposited by Direct Participants with the Depositary are registered in the name of the Depositary's partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of the Depositary. The deposit of series D notes with the Depositary and their registration in the name of Cede & Co. or such other nominee effect no change in beneficial ownership. The Depositary has no knowledge of the actual Beneficial Owners of the series D notes; the Depositary's records reflect only the identity of the Direct Participants to whose accounts such series D notes are credited, which may or may not be the Beneficial Owners. The Direct and Indirect Participants remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by the Depositary to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners are governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

Neither the Depositary nor Cede & Co. (nor any other nominee of the Depositary) will consent or vote with respect to the series D notes unless authorized by a Direct Participant in accordance with the Depositary's procedures. Under its usual procedures, the Depositary mails an Omnibus Proxy to MEHC as soon as possible after the record date. The Omnibus Proxy assigns Cede & Co.'s consenting or voting rights to those Direct Participants to whose accounts the notes are credited on the record date (identified in a listing attached to the Omnibus Proxy).

Principal (and premium, if any) and interest payments on the series D notes and any redemption payments are made to Cede & Co. (or such other nominee as may be requested by an authorized representative of the Depositary). The Depositary's practice is to credit Direct Participants' accounts upon the Depositary's receipt of funds and corresponding detail information from MEHC or the trustee on the payable date in accordance with their respective holdings shown on the Depositary's records. Payments by Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in "street name," and will be the responsibility of such Participant and not of the Depositary, the trustee or MEHC, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of principal (and premium, if any), interest and any redemption proceeds to Cede & Co. (or such other nominee as may be requested by an authorized representative of the Depositary) is the responsibility of MEHC, disbursements of such payments to Direct Participants shall be the responsibility of the Depositary, and disbursement of such payments to the Beneficial Owners shall be the responsibility of Direct and Indirect Participants.

The Depositary may discontinue providing its services as securities depositary with respect to the series D notes at any time by giving reasonable notice to MEHC or the trustee. Under such circumstances, in the event that a successor securities depositary is not obtained, certificated series D notes are required to be printed and delivered. MEHC may decide to discontinue use of the system of book-entry transfers through the Depositary (or a successor securities depositary). In that event, certificated series D notes will be printed and delivered.

The information in this section concerning the Depositary and the Depositary's book-entry system has been obtained from sources that MEHC believes to be reliable, but MEHC, the initial purchasers and the trustee take no responsibility for the accuracy thereof.

A Global Note of any series may not be transferred except as a whole by the Depositary to a nominee or successor of the Depositary or by a nominee of the Depositary to another nominee of the Depositary. A Global Note representing series D notes is exchangeable, in whole but not in part, for series D notes in definitive form of like tenor and terms if (1) the Depositary notifies MEHC that it is unwilling or unable to continue as depositary for such Global Note or if at any time the Depositary is no longer eligible to be or in good standing as a "clearing agency" registered under the Exchange Act,

107



and in either case, a successor depositary is not appointed by MEHC within 120 days of receipt by MEHC of such notice or of MEHC becoming aware of such ineligibility, (2) while such Global Note is subject to the transfer restrictions described under "Transfer Restrictions," the book-entry interests in such Global Note cease to be eligible for Depositary services because such series D notes are neither (a) rated in one of the top four categories by a nationally recognized statistical rating organization nor (b) included within a Self-Regulatory Organization system approved by the SEC for the reporting of quotation and trade information of securities eligible for transfer pursuant to Rule 144A under the Securities Act, or (3) MEHC in its sole discretion at any time determines not to have such series D notes represented by a Global Note and notifies the trustee thereof. A Global Note exchangeable pursuant to the preceding sentence shall be exchangeable for series D notes registered in such names and in such authorized denominations as the Depositary shall direct.

108



CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The exchange of original series D notes for series D exchange notes pursuant to the exchange offer will not constitute a taxable event for U.S. federal income tax purposes. The series D exchange notes received by a holder of original series D notes should be treated as a continuation of such holder's investment in the original series D notes; thus there should be no material U.S. federal income tax consequences to holders exchanging original series D notes for series D exchange notes. As a result:

•  a holder of original series D notes will not recognize taxable gain or loss as a result of the exchange of original series D notes for series D exchange notes pursuant to the exchange offer;
•  the holding period of the series D exchange notes will include the holding period of the original series D notes surrendered in exchange therefor; and
•  a holder's adjusted tax basis in the series D exchange notes will be the same as such holder's adjusted tax basis in the original series D notes surrendered in exchange therefor.

109



PLAN OF DISTRIBUTION

Based on existing interpretations of the Securities Act by the staff of the SEC set forth in several no-action letters to third parties, and subject to the immediately following sentence, we believe that the series D exchange notes that will be issued pursuant to the exchange offer may be offered for resale, resold and otherwise transferred by the holders thereof without further compliance with the registration and prospectus delivery provisions of the Securities Act. However, any purchaser of series D notes who is an "affiliate" (within the meaning of the Securities Act) of ours or who intends to participate in the exchange offer for the purpose of distributing the series D exchange notes or a broker-dealer (within the meaning of the Securities Act) that acquired original series D notes in a transaction other than as part of its market-making or other trading activities and who has arranged or has an understanding with any person to participate in the distribution of the series D exchange notes: (1) will not be able to rely on the interpretations by the staff of the SEC set forth in the above-mentioned no-action letters; (2) will not be able to tender its original series D notes in the exchange offer; and (3) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the series D notes unless such sale or transfer is made pursuant to an exemption from such requirements.

Each broker-dealer that receives series D exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such series D exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of series D exchange notes received in exchange for original series D notes where such original series D notes were acquired as a result of market-marketing activities or other trading activities. We have agreed that, for a period of 120 days after the expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until April 15, 2004, all dealers effecting transactions in the series D exchange notes may be required to deliver a prospectus.

We will not receive any proceeds from any such sale of series D exchange notes by broker-dealers. Series D exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the series D exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker/dealer and/or the purchasers of any such series D exchange notes. Any broker-dealer that resells series D exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such series D exchange notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of series D exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letters of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

For a period of 120 days after the expiration date we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the series D notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the series D notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

110



NOTICE TO CANADIAN RESIDENTS

Any resale of the series D notes in Canada must be made under applicable securities laws which will vary depending on the relevant jurisdiction, and which may require resales to be made under available statutory exemptions or under a discretionary exemption granted by the applicable Canadian securities regulatory authority. Note holders resident in Canada are advised to seek legal advice prior to any resale of the series D notes.

LEGAL MATTERS

Certain legal matters with respect to the series D exchange notes will be passed upon for us by Willkie Farr & Gallagher LLP, New York, New York.

EXPERTS

The consolidated financial statements of MidAmerican Energy Holdings Company and subsidiaries, as of December 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003, included in this prospectus, and the related financial statement schedules included elsewhere in the registration statement, have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph referring to MidAmerican's changes in 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), and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We file reports and information statements and other information with the SEC. Such reports, proxy and information statements and other information filed by us with the SEC can be inspected and copied at the Public Reference Section of the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, and at the regional offices of the SEC located at Woolworth Building, 233 Broadway, New York, New York 10279 and 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of such material can be obtained from the Public Reference Section of the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 at prescribed rates. The SEC maintains a Web site that contains reports, proxy and information statements and other materials that are filed through the SEC's Electronic Data Gathering, Analysis, and Retrieval (EDGAR) system. This Web site can be accessed at http://www.sec.gov.

We make available free of charge through our internet website at http://www.midamerican.com our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after we electronically file with, or furnish it to, the SEC. Any information available on or through our website is not part of this prospectus and our web address is included as an inactive textual reference only.

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FINANCIAL STATEMENTS

Index to Financial Statements


Independent Auditors' Report   F-2  
       
Consolidated Balance Sheets as of December 31, 2003 and 2002   F-3  
       
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002
and 2001		   F-4  
       
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2003, 2002 and 2001   F-5  
       
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002
and 2001		   F-6  
       
Notes to Consolidated Financial Statements   F-7  

F-1



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)

F-2



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.

F-3



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.

F-4



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.

F-5



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.

F-6



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.

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").

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

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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

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.

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

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$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

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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

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.

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

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

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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 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.

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.

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

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

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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.

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 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

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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;

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•  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

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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

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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 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. for the

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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.

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.

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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.

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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

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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

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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  

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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.

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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.

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.

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  

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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

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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.

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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  

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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.

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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

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 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

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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 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.

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.

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

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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.

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

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.

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.

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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  

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


  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 ) 

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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:


Asset Category Percentage of Plan Assets
at December 31 Target
Range
2003 2002
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:


Asset Category Percentage of Plan Assets
at December 31 Target
Range
2003 2002
Equity securities   49 %    34 %    45-55 % 
Debt securities   48     48     45-55  
Real estate   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

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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 % 

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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 % 

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
  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

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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

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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.

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.

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.

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.

Air Quality

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

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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 ("NOX") 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, NOX 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 NOX 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.

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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.

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

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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

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

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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

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.

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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  

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  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  

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  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.

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DEALER PROSPECTUS DELIVERY OBLIGATION

Until April 15, 2004, all dealers that effect transactions in these securities, whether or not participating in the offering, may be required to deliver a prospectus. This is in addition to the dealer's obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

All tendered original series D notes, executed letters of transmittal, and other related documents should be directed to the exchange agent. Requests for assistance and for additional copies of this prospectus, the letter of transmittal and other related documents should be directed to the exchange agent.

EXCHANGE AGENT:

THE BANK OF NEW YORK

By Facsimile:
(212) 298-1915

Confirm by telephone:
(212) 815-5098

By Mail, Hand or Courier:
The Bank of New York
Corporate Trust Department
Reorganization Unit
101 Barclay Street
Floor 7 East
New York, New York 10286



PART II
INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20.    Indemnification of Directors and Officers

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to the Registrant's directors and officers pursuant to the following provisions or otherwise, the Registrant has been advised that, although the validity and scope of the governing statute have not been tested in court, in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In addition, indemnification may be limited by state securities laws.

Sections 490.850-490.859 of the Iowa Business Corporation Act permit corporations organized thereunder to indemnify directors, officers, employees and agents against liability under certain circumstances. The Restated Articles of Incorporation, as amended, and the Restated Bylaws, as amended, of MidAmerican Energy Holdings Company provide for indemnification of directors, officers and employees to the full extent provided by the Iowa Business Corporation Act. The Articles of Incorporation and the Bylaws state that the indemnification provided therein shall not be deemed exclusive. MidAmerican Energy Holdings Company may purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of MidAmerican Energy Holdings Company or another corporation, partnership, joint venture, trust or other enterprise against any expense, liability or loss, whether or not MidAmerican Energy Holdings Company would have the power to indemnify such person against such expense, liability or loss under the Iowa Business Corporation Act. Pursuant to Section 490.857 of the Iowa Business Corporation Act, the Articles of Incorporation and the Bylaws, MidAmerican Energy Holdings Company, through MidAmerican Energy Holdings Company, maintains directors' and officers' liability insurance coverage. MidAmerican Energy Holdings Company has also entered into indemnification agreements with certain directors and officers, and expects to enter into similar agreements with future directors and officers, to further assure such persons indemnification as permitted by Iowa law.

As permitted by Section 490.202 of the Iowa Business Corporation Act and Article XI.B. of the Articles of Incorporation, the Articles of Incorporation are deemed to provide that no director shall be personally liable to MidAmerican Energy Holdings Company or its shareholders for money damages for any action taken, or any failure to take any action, as a director, except liability for any of the following: (1) the amount of a financial benefit received by a director to which the director is not entitled; (2) an intentional infliction of harm on the corporation or the shareholders; (3) a violation of section 490.833 (relating to certain unlawful distributions to shareholders); or (4) an intentional violation of criminal law.

The Registrant's Amended and Restated Articles of Incorporation and Bylaws provides that if the proceeding for which indemnification is sought is by or in the right of the Registrant, indemnification may be made only for reasonable expenses and may not be made in any proceeding in which the person is adjudged liable to the Registrant. Further, any such person may not be indemnified in any proceeding that charges improper personal benefit to the person in which the person is adjudged to be liable.

The Registrant's Amended and Restated Articles of Incorporation and Bylaws allow the Registrant to maintain liability insurance to protect itself and any director, officer, employee, or agent against any expense, liability or loss whether or not the Registrant would have the power to indemnify such person against such incurred expense, liability, or loss.

The Registrant has also entered into indemnification agreements with certain directors and officers, and expects to enter into similar agreements with future directors and officers, to further assure such persons' indemnification as permitted by Iowa law.

The rights to indemnification conferred on any person by the Registrant's Amended and Restated Articles of Incorporation and Bylaws are not exclusive of any right which any person may have or acquire under any statute, provision of the Registrant's Amended and Restated Articles of Incorporation, Bylaws, agreement, or vote of shareholders or disinterested directors.

II-1



Item 21.    Exhibits and Financial Statement Schedules.

(a) Exhibits


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 (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   Second Supplemental Indenture, dated May 16, 2003, by and between MEHC and the Bank of New York relating to the 3.50% Senior Notes due 2008 (incorporated by reference to Exhibit 4.3 of MEHC's Registration Statement No. 333-105690 dated May 30, 2003).
  4.4   Third Supplemental Indenture, dated February 12, 2004, by and between MEHC and the Bank of New York relating to the 5.00% Senior Notes due 2013.*
  4.5   Registration Rights Agreement, dated as of February 9, 2004, by and among MEHC, and Credit Suisse First Boston and Lehman Brothers Inc.*
  4.6   Indenture for the 6 ¼% 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).
  4.7   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).
  4.8   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).
  4.9   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.)
  4.10   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).
  4.11   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).

II-2




Exhibit No.  
  4.12   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).
  4.13   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).
  4.14   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).
  4.15   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).
  4.16   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).
  4.17   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).
  4.18   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).
  4.19   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).
  4.20   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).
  4.21   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).
  5.1   Opinion of Willkie Farr & Gallagher LLP.**
  8.1   Opinion of Willkie Farr & Gallagher LLP with respect to certain tax matters.**
  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).

II-3




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's Annual 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).

II-4




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).
  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).

II-5




Exhibit No.  
  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).
  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).

II-6




Exhibit No.  
  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 to 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 to 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 to 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 to 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 to 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 to 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 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2003).
  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).

II-7




Exhibit No.  
  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).
  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).

II-8




Exhibit No.  
  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).
  12.1   Statement regarding computation of ratio of earnings to fixed charges.*
  14.1   MidAmerican Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers (incorporated by reference to Exhibit 14.1 to 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 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2003).
  23.1   Consent of Willkie Farr & Gallagher LLP (included in their opinions filed as Exhibit 5.1 and 8.1).**
  23.2   Consent of Deloitte & Touche LLP.**
  24.1   Power of Attorney.*
  25.1   Statement on Form T-1 of Eligibility of Trustee relating to the 5.00% Senior Notes due 2014.*
  99.1   Form of Letter of Transmittal relating to the 5.00% Senior Notes due 2014.*
  99.2   Form of Notice of Guaranteed Delivery relating to the 5.00% Senior Notes due 2014.*
  99.3   Form of Letter to Clients relating to the 5.00% Senior Notes due 2014.*
  99.4   Form of Letter to Nominees relating to the 5.00% Senior Notes due 2014.*

*   Previously filed.

** Filed herewith.

II-9



Item 22.    Undertakings

The undersigned registrant hereby undertakes that, for the purposes of determining any liability under the Securities Act, each filing of the registrant's annual report pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan's annual report pursuant to Section 15(d) of the Exchange Act) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant, pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by any such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether or not such indemnification is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1)  For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective
(2)  For purposes of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11 or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

The undersigned registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

II-10



SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Des Moines, State of Iowa, on the 5th day of March, 2004.

MIDAMERICAN ENERGY HOLDINGS COMPANY

By: /s/    Douglas L. Anderson

Douglas L. Anderson
Senior Vice President and General Counsel

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons, in the capacities and on the dates indicated.

Signature Title Date
* Chairman of the Board of Directors,
Chief Executive Officer and Director
(principal executive officer)		 March 5, 2004
David L. Sokol
* President, Chief Operating Officer and Director March 5, 2004
Gregory E. Abel
* Senior Vice President and Chief
Financial Officer (principal financial
officer)		 March 5, 2004
Patrick J. Goodman
* Director March 5, 2004
Edgar D. Aronson
* Director March 5, 2004
Stanley J. Bright
* Director March 5, 2004
Walter Scott, Jr.
* Director March 5, 2004
Marc D. Hamburg
* Director March 5, 2004
Warren E. Buffett
* Director March 5, 2004
John K. Boyer
* Director March 5, 2004
W. David Scott
* Director March 5, 2004
Richard R. Jaros

II-11



Douglas L. Anderson, by signing his name below, signs this document on behalf of each of the above-named persons specified by an asterisk(*) pursuant to a power of attorney duly executed by such persons filed with the Securities and Exchange Commission in the Registrant's Registration Statement on Form S-4 on February 23, 2004.

/s/ Douglas L. Anderson
Douglas L. Anderson
Attorney-in-fact

II-12



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 financial statements are an integral part of this
financial statement schedule.

S-1



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 financial statements are an integral part of this
financial statement schedule.

S-2



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 financial statements are an integral part of this
financial statement schedule.

S-3



Schedule II

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2003
(Amounts in thousands)


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

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

S-4



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 (incorporated by reference to Exhibit 4.2 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.3   Second Supplemental Indenture, dated May 16, 2003, by and between MEHC and the Bank of New York relating to the 3.50% Senior Notes due 2008 (incorporated by reference to Exhibit 4.3 of MEHC's Registration Statement No. 333-105690 dated May 30, 2003).
  4.4   Third Supplemental Indenture, dated February 12, 2004, by and between MEHC and the Bank of New York relating to the 5.00% Senior Notes due 2013.
  4.5   Registration Rights Agreement, dated as of February 9, 2004, by and among MEHC, and Credit Suisse First Boston and Lehman Brothers, Inc.
  4.6   Indenture for the 6 ¼% 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).
  4.7   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).
  4.8   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).
  4.9   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.)
  4.10   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).
  4.11   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).



Exhibit No.  
  4.12   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).
  4.13   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).
  4.14   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).
  4.15   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).
  4.16   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).
  4.17   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).
  4.18   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).
  4.19   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).
  4.20   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).
  4.21   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).
  5.1   Opinion of Willkie Farr & Gallagher LLP.**
  8.1   Opinion of Willkie Farr & Gallagher LLP with respect to certain tax matters.**
  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).



Exhibit No.  
  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).
  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's Annual 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).



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).
  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).



Exhibit No.  
  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).
  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).



Exhibit No.  
  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 to 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 to 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 to 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 to 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 to 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 to 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 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2003).
  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).



Exhibit No.  
  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).
  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).



Exhibit No.  
  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).
  12.1   Statement regarding computation of ratio of earnings to fixed charges.*
  14.1   MidAmerican Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers (incorporated by reference to Exhibit 14.1 to 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 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2003).
  23.1   Consent of Willkie Farr & Gallagher LLP (included in their opinions filed as Exhibit 5.1 and 8.1).**
  23.2   Consent of Deloitte & Touche LLP.**
  24.1   Power of Attorney.*
  25.1   Statement on Form T-1 of Eligibility of Trustee relating to the 5.00% Senior Notes due 2014.*
  99.1   Form of Letter of Transmittal relating to the 5.00% Senior Notes due 2014.*
  99.2   Form of Notice of Guaranteed Delivery relating to the 5.00% Senior Notes due 2014.*
  99.3   Form of Letter to Clients relating to the 5.00% Senior Notes due 2014.*
  99.4   Form of Letter to Nominees relating to the 5.00% Senior Notes due 2014.*
* Previously filed.
** Filed herewith.