UNITEDSTATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C.20549

FORM 10-K/A

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

For thefiscal year ended December 31, 2003

Commission FileNo. 0-25551

MIDAMERICAN ENERGY HOLDINGSCOMPANY

(Exact name of registrant as specifiedin itscharter)

|                                                              |  |                                     |  |  |  |  |
|--------------------------------------------------------------|--|-------------------------------------|--|--|--|--|
| Iowa                                                         |  | 94-2213782                          |
| (Stateor other jurisdiction ofincorporation or organization) |  | (I.R.S. EmployerIdentification No.) |
| 666Grand Avenue, Des Moines, IA                              |  | 50309                               |
| (Addressof principal executive offices)                      |  | (ZipCode)                           |
|                                                              |

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

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

Securities registeredpursuant to Section 12(g) of the Act: N/A

Indicate by check mark whether the registrant: (1) has filedall reports required to be filed by Section 13 or 15(d) of theSecurities Exchange Act of 1934 during the preceding 12 months (or forsuch shorter period that the registrant was required to file suchreports), and (2) has been subject to such filing requirements for thepast 90 days. Yes     No 

Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein and will not be contained, tothe best of each of the registrants' knowledge, in definitiveproxy or information statements incorporated by reference in Part IIIof this Form 10-K or any amendment to this Form 10-K. 

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

All of the shares of common equity of MidAmericanEnergy Holdings Company are held by a limited group of privateinvestors. As of January 31, 2004, 9,081,087 shares of common stockwere outstanding.

----

TABLE OFCONTENTS

PART I

|        |  |                                                    |  |    |  |  |  |  |  |  |
|--------|--|----------------------------------------------------|--|----|--|--|--|--|--|--|
| Item1. |  | Business                                           |  | 4  |
| Item2. |  | Properties                                         |  | 33 |
| Item3. |  | Legal Proceedings                                  |  | 35 |
| Item4. |  | Submission of Matters to a Vote of SecurityHolders |  | 37 |
|        |

PART II

|         |  |                                                                                                            |  |     |  |  |  |  |  |  |
|---------|--|------------------------------------------------------------------------------------------------------------|--|-----|--|--|--|--|--|--|
| Item5.  |  | Marketfor Registrant's Common Equity, Related Stockholder Matters andIssuer Purchases of Equity Securities |  | 38  |
| Item6.  |  | Selected Financial Data                                                                                    |  | 38  |
| Item7.  |  | Management's Discussion and Analysis of FinancialCondition and Results of Operations                       |  | 39  |
| Item7A. |  | Quantitative and Qualitative Disclosures About Market Risk                                                 |  | 54  |
| Item 8. |  | Financial Statements andSupplementary Data                                                                 |  | 56  |
| Item9.  |  | Changes in and Disagreements with Accountants on Accountingand Financial Disclosure                        |  | 100 |
| Item9A. |  | Controls andProcedures                                                                                     |  | 100 |
|         |

PART III

|          |  |                                                                                              |  |     |  |  |  |  |  |  |
|----------|--|----------------------------------------------------------------------------------------------|--|-----|--|--|--|--|--|--|
| Item10.  |  | Directorsand Executive Officers of the Registrant                                            |  | 101 |
| Item11.  |  | Executive Compensation                                                                       |  | 102 |
| Item12.  |  | Security Ownership of Certain Beneficial Owners andManagementand Related Stockholder Matters |  | 107 |
| Item13.  |  | Certain Relationships and Related Transactions                                               |  | 108 |
| Item 14. |  | Principal AccountantFees and Services                                                        |  | 109 |
|          |

PART IV

|         |  |                                                                |  |     |  |  |  |  |  |  |
|---------|--|----------------------------------------------------------------|--|-----|--|--|--|--|--|--|
| Item15. |  | Exhibits,Financial Statement Schedules and Reports on Form 8-K |  | 110 |
|         |

|              |  |     |  |  |  |  |
|--------------|--|-----|--|--|--|--|
| SIGNATURES   |  | 115 |
| EXHIBITINDEX |  | 117 |
|              |

EXPLANATORY NOTE

TheCompany originally filed its Annual Report on Form 10-K on February 9,2004. In accordance with accounting guidance issued subsequent to thatdate, the Company is amending its originally filed Annual Report onForm 10-K to reflect the reclassification of 2002 and prioryears' regulatory liabilities for the cost of removal of utilityplant previously recognized within accumulated depreciation as an otherlong-term accrued liability. This amendment does not reflect eventsoccurring after the original filing of the Form 10-K or modify orupdate those disclosures except as stated in the precedingsentence.

----

Disclosure RegardingForward-Looking Statements

This report contains statements thatdo not directly or exclusively relate to historical facts. Thesestatements are "forward-looking statements"within the meaning of the Private Securities Litigation Reform Act of1995. You can typically identify forward-looking statements by the useof forward-looking words, such as "may","will", "could","project","believe","anticipate","expect","estimate","continue","potential","plan", "forecast",and similar terms. These statements represent plans, expectations andbeliefs and are subject to risks, uncertainties and other factors. Manyof these factors are outside the Company's control and couldcause actual results to differ materially from such forward-lookingstatements. These factors include, among others:

|              |                                                                                                  |
|--------------|--------------------------------------------------------------------------------------------------|
| •  | general economic and business conditionsin the jurisdictions in which its facilities arelocated; |

|              |                                                                                        |
|--------------|----------------------------------------------------------------------------------------|
| •  | the financial condition andcreditworthiness of our significant customers andsuppliers; |

|              |                                                                                                                                                                                     |
|--------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| •  | governmental, statutory,regulatory or administrative initiatives or ratemaking actionsaffecting the Company or the electric or gas utility, pipeline or powergeneration industries; |

|              |                                      |
|--------------|--------------------------------------|
| •  | weathereffects on sales and revenue; |

|              |                         |
|--------------|-------------------------|
| •  | generalindustry trends; |

|              |                                                                                               |
|--------------|-----------------------------------------------------------------------------------------------|
| •  | increasedcompetition in the power generation, electric and gas utility orpipeline industries; |

|              |                                       |
|--------------|---------------------------------------|
| •  | fuel and powercosts and availability; |

|              |                                                   |
|--------------|---------------------------------------------------|
| •  | continuedavailability of accessible gas reserves; |

|              |                                                                                     |
|--------------|-------------------------------------------------------------------------------------|
| •  | changes in business strategy, developmentplans or customer or vendor relationships; |

|              |                                              |
|--------------|----------------------------------------------|
| •  | availability, term and deployment ofcapital; |

|              |                                     |
|--------------|-------------------------------------|
| •  | availability of qualifiedpersonnel; |

|              |                                |
|--------------|--------------------------------|
| •  | unscheduled outages orrepairs; |

|              |                                      |
|--------------|--------------------------------------|
| •  | risks relating to nucleargeneration; |

|              |                                                                                                                                                                                                                                                                  |
|--------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| •  | financial or regulatoryaccounting principles or policies imposed by the Public CompanyAccounting Oversight Board, the Financial Accounting Standards Board("FASB"), the Securities and ExchangeCommission ("SEC") and similar entities withregulatory oversight; |

|              |                                                                                                                       |
|--------------|-----------------------------------------------------------------------------------------------------------------------|
| •  | other risks orunforeseen events, including wars, the effects of terrorism, embargosand other catastrophic events; and |

|              |                                                                                                                                                       |
|--------------|-------------------------------------------------------------------------------------------------------------------------------------------------------|
| •  | other business or investmentconsiderations that may be disclosed from time to time in SEC filingsor in other publicly disseminated written documents. |

MEHCundertakes no obligation to publicly update or revise anyforward-looking statements, whether as a result of new information,future events or otherwise. The foregoing review of factors should notbe construed as exclusive.

3

----

PART I

Item1.    Business.

General

MidAmerican Energy HoldingsCompany ("MEHC") and its subsidiaries(together with MEHC, the "Company") is aUnited States-based privately owned global energy company. TheCompany's operations are organized and managed on seven distinctplatforms: MidAmerican Energy Company ("MidAmericanEnergy"), Kern River Gas Transmission Company("Kern River"), Northern Natural Gas Company("Northern Natural Gas"), CE Electric UKFunding ("CE Electric UK") (which includesNorthern Electric plc ("Northern Electric")and Yorkshire Electricity Group plc("Yorkshire")), CalEnergy Generation –Domestic (interests in independent power projects and relatedoperations), CalEnergy Generation – Foreign (thesubsidiaries owning the Upper Mahiao, Malitbog and Mahanagdong projects(collectively, the "Leyte Projects") and theCasecnan project) and HomeServices of America, Inc. (collectively withits subsidiaries, "HomeServices"). Refer toNote 20 in "Item 8. Financial Statements and SupplementaryData — Notes to Consolidated Financial Statements"for additional segment information regarding the Company'splatforms. Through these platforms, the Company owns and operates acombined electric and natural gas utility company in the United States,two natural gas pipeline companies in the United States, twoelectricity distribution companies in the United Kingdom, a diversifiedportfolio of domestic and international independent power projects andthe second largest residential real estate brokerage firm in the UnitedStates.

MEHC's energy subsidiaries generate, transmit,store, distribute and supply energy. MEHC's electric and naturalgas utility subsidiaries currently serve approximately 4.4 millionelectricity customers and approximately 670,000 natural gas customers.Its natural gas pipeline subsidiaries operate interstate natural gastransmission systems with approximately 18,200 miles of pipeline inoperation and peak delivery capacity of 6.2 billion cubic feet ofnatural gas per day. The Company has interests in 6,716 net ownedmegawatts of power generation facilities in operation and construction,including 5,142 net owned megawatts in facilities that are part of theregulated return asset base of its electric utility business and 1,574net owned megawatts in non-utility power generation facilities.Substantially all of the non-utility power generation facilities havelong-term contracts for the sale of energy and/or capacity from thefacilities.

On March 14, 2000, MEHC and an investor groupcomprised of Berkshire Hathaway Inc. ("BerkshireHathaway"), Walter Scott, Jr., a director of MEHC, DavidL. Sokol, Chairman and Chief Executive Officer of MEHC, and Gregory E.Abel, President and Chief Operating Officer of MEHC, closed on adefinitive agreement and plan of merger whereby the investor group,together with certain of Mr. Scott's family members and familytrusts and corporations, acquired all of the outstanding common stockof MEHC (the "Teton Transaction").

Theprincipal executive offices of MEHC are located at 666 Grand Avenue,Des Moines, Iowa 50309 and its telephone number is (515) 242-4300. MEHCinitially incorporated in 1971 under the laws of the State of Delawareand was reincorporated in 1999 in Iowa, at which time it changed itsname from CalEnergy Company, Inc. to MidAmerican Energy HoldingsCompany.

In this Annual Report, references to "U.S.dollars," "dollars,""$" or "cents" areto the currency of the United States, references to"pounds sterling,""£,""sterling," "pence"or "p" are to the currency of the UnitedKingdom and references to "pesos" are to thecurrency of the Philippines. References to kW means kilowatts, MW meansmegawatts, GW means gigawatts, kWh means kilowatt hours, MWh meansmegawatt hours, GWh means gigawatt hours, kV means kilovolts, mmcfmeans million cubic feet, Bcf means billion cubic feet, Tcf meanstrillion cubic feet, MMBtus means million British thermal units and Dthmeans decatherms or MMBtus.

4

----

MidAmerican Energy

Business

Through MidAmerican Energy, MEHC owns apublic utility company headquartered in Iowa with $4.4 billion ofassets as of December 31, 2003, and operating revenues for 2003totaling $2.6 billion. MidAmerican Energy is principally engaged in thebusiness of generating, transmitting, distributing and selling electricenergy 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; theQuad Cities (Davenport and Bettendorf, Iowa and Rock Island, Moline andEast 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 andareas. As of December  31, 2003, MidAmerican Energy hadapproximately 689,000 retail electric customers and 668,000 retailnatural gas customers.

In addition to retail sales, MidAmericanEnergy sells electric energy and natural gas to other utilities,marketers and municipalities. These sales are referred to as wholesalesales. It also transports natural gas through its distribution systemfor a number of end-use customers who have independently secured theirsupply of natural gas.

MidAmerican Energy's regulatedelectric and gas operations are conducted under franchises,certificates, permits and licenses obtained from state and localauthorities. The franchises, with various expiration dates, aretypically for 25-year terms.

MidAmerican Energy has a diversecustomer base consisting of residential, agricultural, and a variety ofcommercial and industrial customer groups. Among the primary industriesserved by MidAmerican Energy are those that are concerned with foodproducts, the manufacturing, processing and fabrication of primarymetals, real estate, farm and other non-electrical machinery, andcement and gypsum products.

MidAmerican Energy also conducts anumber of nonregulated business activities.

For the year endedDecember 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 itsnonregulated business activities. For 2002 and 2001, the correspondingpercentages were 61% electric, 31% gas and 8%nonregulated; and 56% electric, 37% gas and 7%nonregulated, respectively.

ElectricOperations

The electric utility industry continues toundergo regulatory change. Traditionally, prices charged by electricutility companies have been regulated by federal and state commissionsand have been based on cost of service. In recent years, changes havebeen occurring that move the electric utility industry toward a morecompetitive, market-based pricing environment. These changes may have asignificant impact on MidAmerican Energy's business.

MidAmerican Energy manages its operations as four separate businessunits: generation, energy delivery, transmission, and marketing andsales. The generation segment derives most of its revenue from the saleof regulated wholesale electricity and non-regulated wholesale andretail natural gas. The energy delivery segment derives its revenueprincipally from the delivery of regulated electricity and natural gas,while the transmission segment obtains most of its revenue from thesale of electric transmission capacity. The marketing and sales segmentreceives its revenue principally from non-regulated sales of naturalgas and electricity.

For the year ended December 31, 2003,regulated electric sales by MidAmerican Energy by customer class wereas follows: 19.4% were to residential customers, 14.0%were to small general service customers, 25.4% were to largegeneral service customers, 8.5% were to other customers, and32.7% were wholesale sales. For the year ended December 31,2003, regulated electric sales by MidAmerican Energy by jurisdictionwere as follows: 88.8% to Iowa, 10.4% to Illinois and0.8% to South Dakota.

The annual hourly peak demand onMidAmerican Energy's electric system usually occurs as a resultof air conditioning use during the cooling season. In August 2003,MidAmerican Energy reached a new 

5

----

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

The followingtable sets out certain information concerning MidAmericanEnergy's power generation facilities based upon summer 2003accreditation:

|                                            |  |                            |        |                 |  |        |        |          |  |           |         |        |  |        |          |        |  |        |           |        |  |  |
|--------------------------------------------|--|----------------------------|--------|-----------------|--|--------|--------|----------|--|-----------|---------|--------|--|--------|----------|--------|--|--------|-----------|--------|--|--|
| Operating Project(1)                       |  | FacilityNetCapacity(MW)(2) |        | Net MW Owned(2) |  | Fuel   |        | Location |  | Operation |
| CoalFacilities:                            |  |                       |   |            |  |   |   |     |  |      |    |   |  |   |     |   |  |   |      |   |
| CouncilBluffs Energy Center Units 1 &2 |  |                       | 133    |            |  |   | 133    |     |  |      | Coal    |   |  |   | Iowa     |   |  |   | 1954,1958 |   |
| Council Bluffs Energy Center Unit3         |  |                       | 690    |            |  |   | 546    |     |  |      | Coal    |   |  |   | Iowa     |   |  |   | 1978      |   |
| LouisaGenerationStation                    |  |                       | 700    |            |  |   | 616    |     |  |      | Coal    |   |  |   | Iowa     |   |  |   | 1983      |   |
| NealGeneration Station Units 1 &2      |  |                       | 435    |            |  |   | 435    |     |  |      | Coal    |   |  |   | Iowa     |   |  |   | 1964,1972 |   |
| Neal Generation Station Unit3              |  |                       | 515    |            |  |   | 371    |     |  |      | Coal    |   |  |   | Iowa     |   |  |   | 1975      |   |
| NealGeneration Station Unit4               |  |                       | 644    |            |  |   | 261    |     |  |      | Coal    |   |  |   | Iowa     |   |  |   | 1979      |   |
| OttumwaGenerationStation                   |  |                       | 708    |            |  |   | 368    |     |  |      | Coal    |   |  |   | Iowa     |   |  |   | 1981      |   |
| RiversideGenerationStation                 |  |                       | 135    |            |  |   | 135    |     |  |      | Coal    |   |  |   | Iowa     |   |  |   | 1925-61   |   |
| Total coalfacilities                       |  |                       | 3,960  |            |  |   | 2,865  |     |  |      |    |   |  |   |     |   |  |   |      |   |
| OtherFacilities:                           |  |                       |   |            |  |   |   |     |  |      |    |   |  |   |     |   |  |   |      |   |
| CombustionTurbines                         |  |                       | 1,112  |            |  |   | 1,112  |     |  |      | Gas/Oil |   |  |   | Iowa     |   |  |   | 1969-2003 |   |
| MolineWaterPower                           |  |                       | 3      |            |  |   | 3      |     |  |      | Hydro   |   |  |   | Illinois |   |  |   | 1970      |   |
| QuadCities GeneratingStation               |  |                       | 1,748  |            |  |   | 437    |     |  |      | Nuclear |   |  |   | Illinois |   |  |   | 1974      |   |
| PortablePowerModules                       |  |                       | 56     |            |  |   | 56     |     |  |      | Oil     |   |  |   | Iowa     |   |  |   | 2000      |   |
| Totalotherfacilities                       |  |                       | 2,919  |            |  |   | 1,608  |     |  |      |    |   |  |   |     |   |  |   |      |   |
|                                       |  |                       |   |            |  |   |   |     |  |      |    |   |  |   |     |   |  |   |      |   |
| Accreditedgeneratingcapacity               |  |                       | 6,879  |            |  |   | 4,473  |     |  |      |    |   |  |   |     |   |  |   |      |   |
| ProjectsUnderConstruction:                 |  |                       |   |            |  |   |   |     |  |      |    |   |  |   |     |   |  |   |      |   |
| GreaterDes Moines Energy Center(3)         |  |                       | 190    |            |  |   | 190    |     |  |      | Gas     |   |  |   | Iowa     |   |  |   | 2004      |   |
| CouncilBluffs Energy Center Unit4          |  |                       | 790    |            |  |   | 479    |     |  |      | Coal    |   |  |   | Iowa     |   |  |   | 2007      |   |
| TotalPower GenerationCapacity              |  |                       | 7,859  |            |  |   | 5,142  |     |  |      |    |   |  |   |     |   |  |   |      |   |
|                                            |

|           |                                                                                                                                          |
|-----------|------------------------------------------------------------------------------------------------------------------------------------------|
| (1)  | MidAmericanEnergy operates all such power generation facilities other than QuadCities Generating Station and Ottumwa Generation Station. |

|           |                                                                                                                                                                                                                                                                                      |
|-----------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2)  | Represents accredited net generatingcapability. Actual MW may vary depending on operating conditions andplant design for operating projects. Net MW owned indicates ownershipof accredited capacity for the summer of 2003 as approved by theMid-Continent Area Power Pool ("MAPP"). |

|           |                                                                                                                                                                                              |
|-----------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (3)  | The Greater Des Moines Energy Centercommenced commercial operations in May 2003. Since May 2003, 327 MW(included in "Other Facilities — CombustionTurbines" above) has been available. |

MidAmericanEnergy's accredited net generating capability in the summer of2003 was 4,787 MW. Accredited net generating capability represents theamount of generation available to meet the requirements on MidAmericanEnergy's system and consists of MidAmerican Energy-ownedgeneration of 4,473 MW, generation under power purchase contracts of630 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 wouldotherwise be due to regulatory restrictions, fuel restrictions andgenerating units being temporarily out of service for inspection,maintenance, refueling or modifications.

MidAmerican Energyanticipates a continuing increase in demand for electricity from itsregulated customers. To meet anticipated demand and ensure adequateelectric generation in its service territory, MidAmerican Energy iscurrently constructing two electric generating projects in Iowa and isdeveloping a third. Upon completion, the projects will provide serviceto regulated retail electricity customers. 

6

----

MidAmerican Energy has obtained regulatoryapproval to include the actual costs of the generation projects in itsIowa rate base as long as actual costs do not exceed an agreed upon capthat MidAmerican Energy has deemed to be reasonable. Wholesale salesmay also be made from the projects to the extent the power is notneeded for regulated retail service.

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

The secondproject is currently under construction and will be a 790 MW (based onexpected accreditation) super-critical-temperature, low-sulfurcoal-fired plant. MidAmerican Energy will operate the plant and hold anundivided ownership interest as a tenant in common with the otherowners of the plant. MidAmerican Energy's ownership interest is60.67%, equating to 479 MW of output. MidAmerican Energy expectsits share of the estimated cost of the project to be approximately $713million, excluding allowance for funds used during construction.Municipal, cooperative and public power utilities will own theremainder, which is a typical ownership arrangement for large base-loadplants in Iowa. On May 29, 2003, the Iowa Utilities Board("IUB") issued an order that approves theratemaking principles for the plant, and on June 27, 2003, MidAmericanEnergy received a certificate from the IUB allowing MidAmerican Energyto construct the plant. On February 12, 2003, MidAmerican Energyexecuted a contract with Mitsui & Co. Energy Development, Inc.("Mitsui") for the engineering, procurementand construction of the plant. On September 9, 2003, MidAmerican Energybegan construction of the plant, which it expects to be completed inthe summer of 2007. MidAmerican Energy is also seeking an order fromthe IUB approving construction of the associated transmissionfacilities.

The third project is currently under development andis comprised of wind power facilities totaling 310 MW based on thenameplate rating. Generally speaking, accredited capacity ratings forthe wind power facilities are considerably less than the nameplateratings due to the varying nature of wind. The current projectedaccredited capacity for these wind power facilities is approximately 53MW. If constructed, MidAmerican Energy will own and operate thesefacilities, which are expected to cost approximately $323 million.MidAmerican Energy's plan to construct the wind project is inconjunction with a settlement agreement that extends through December31, 2010, an Iowa retail electric rate freeze that was previouslyscheduled to expire at the end of 2005. The settlement agreement, whichwas filed with the IUB in conjunction with MidAmerican Energy'sapplication for ratemaking principles for the wind project, wasapproved by the IUB on October 17, 2003. The obligation of MidAmericanEnergy to construct the wind project may be terminated by MidAmericanEnergy if the federal production tax credit applicable to the windenergy facilities is not available at a rate of 1.8 cents per kWh for aperiod of at least ten years after the facilities begin generatingelectricity. The production tax credit is available only to windfacilities placed in service before January 1, 2004. MidAmerican Energyhas received authorization from the IUB to construct the wind powerproject. If MidAmerican Energy does not construct the wind facilitiesby December 31, 2007, the rate extension from January 1, 2006 throughDecember 31, 2010 may terminate.

MidAmerican Energy isinterconnected with Iowa utilities and utilities in neighboring statesand is party to an electric generation and transmission poolingagreement administered by the Mid-Continent Area Power Pool("MAPP"). MAPP is a voluntary association ofelectric utilities doing business in Minnesota, Nebraska, North Dakotaand the Canadian provinces of Saskatchewan and Manitoba and portions ofIowa, Montana, South Dakota and Wisconsin. Its membership also includespower marketers, regulatory agencies and independent power producers.MAPP facilitates operation of the transmission system, is responsiblefor the safety and reliability of the bulk electric system, and hasresponsibility for administration of MAPP's Open-AccessTransmission Tariff.

Each MAPP participant is required tomaintain for emergency purposes a net generating capability reserve ofat least 15% above its system peak demand. If aparticipant'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 wasapproximately 22%.

7

----

MidAmerican Energy's transmissionsystem connects its generating facilities with distribution substationsand interconnects with 14 other transmission providers in Iowa and fiveadjacent states. Under normal operating conditions, MidAmericanEnergy's transmission system has adequate capacity to deliverenergy to MidAmerican Energy's distribution system and to exportand import energy with other interconnected systems. Refer to"Item 2. Properties" of this Form 10-K foradditional information on transmission lines.

GasOperations

MidAmerican Energy purchases gas supplies fromproducers and third party marketers. To ensure system reliability, ageographically diverse supply portfolio with varying terms and contractconditions is utilized for the gas supplies. MidAmerican Energyattempts to optimize the value of its regulatory assets by engaging insales for resale transactions. IUB and South Dakota Public UtilitiesCommission rulings have allowed MidAmerican Energy to retain 50%of the respective jurisdictional margins earned on sales for resale ofnatural gas, with the remaining 50% being returned to customersthrough the purchased gas adjustment clause discussed below.

MidAmerican Energy has rights to firm pipeline capacity to transport gasto its service territory through direct interconnects to the pipelinesystems of Northern Natural Gas (an affiliate company), Natural GasPipeline Company of America ("NGPL"),Northern Border Pipeline Company ("NorthernBorder") and ANR Pipeline Company("ANR"). At times, the capacity availablethrough MidAmerican Energy's firm capacity portfolio may exceedthe demand on MidAmerican Energy's distribution system. Firmcapacity in excess of MidAmerican Energy's system needs can beresold to other companies to achieve optimum use of the availablecapacity. IUB and South Dakota Public Utilities Commission rulings haveallowed MidAmerican Energy to retain 30% of the respectivejurisdictional margins earned on the resold capacity, with theremaining 70% being returned to customers through the purchasedgas adjustment clause.

MidAmerican Energy's cost of gas isrecovered from customers through purchased gas adjustment clauses. In1995, the IUB gave initial approval of MidAmerican Energy'sIncentive Gas Supply Procurement Program. In November 2003, the IUBextended the program through October 31, 2004. Under the program, asamended, MidAmerican Energy is required to file with the IUB every sixmonths a comparison of its gas procurement costs to an index-basedreference price. If MidAmerican Energy's cost of gas for theperiod is less or greater than an established tolerance band around thereference price, then MidAmerican Energy shares a portion of thesavings or costs with customers. A similar program is currently ineffect in South Dakota through October 31, 2005. Since theimplementation of the program, MidAmerican Energy has successfullyachieved and shared savings with its natural gas customers.

MidAmerican Energy utilizes leased gas storage to meet peak dayrequirements and to manage the daily changes in demand due to changesin weather. The storage gas is typically replaced during the summermonths. In addition, MidAmerican Energy also utilizes three liquefiednatural gas plants and two propane-air plants to meet peak day demandsin the winter. The storage and peak shaving facilities reduceMidAmerican Energy's dependence on gas purchases during thevolatile winter heating season. In addition, MidAmerican Energy hasentered into various financial and physical gas purchase agreements tomitigate the volatility of gas prices during the winter heatingseason.

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

Kern River

Business

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

8

----

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 pipelinesystem 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 mainlinesection and the common facilities. Kern River owns the entire mainlinesection, which extends from the pipeline's point of originationnear Opal, Wyoming through the Central Rocky Mountains area intoDaggett, California. The mainline section is comprised of the original680 miles of 36-inch pipeline and 634.3 miles of 36-inch loop pipelinerelated to the 2003 Expansion Project.

The common facilitiesconsist of a section of pipeline that extends from the point ofinterconnection 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 MojavePipeline Company ("Mojave"), a wholly ownedsubsidiary of El Paso Corporation (approximately 23.2% as ofDecember 31, 2003), as tenants-in-common. Kern River's ownershippercentage in the common facilities will increase or decrease pursuantto subsequently completed expansions by the respective joint owners.Kern River has exclusive rights to approximately 1,570,500 Dth per dayof the common facilities' capacity, and Mojave has exclusiverights to 400,000 Dth per day of capacity. Operation and maintenance ofthe common facilities are the responsibility of Mojave PipelineOperating Company, an affiliate of Mojave.

TransportationService Agreements

As of December 31, 2003, Kern River hadcontracted 1,680,780 Dth per day of capacity under long-term firm gastransportation service agreements under which the pipeline receivesnatural gas on behalf of shippers at designated receipt points,transports the gas on a firm basis up to each shipper's maximumdaily quantity and delivers thermally equivalent quantities of gas atdesignated delivery points. Each shipper pays Kern River the aggregateamount specified in its long-term firm gas transportation serviceagreement and Kern River's tariff, with such amount consistingprimarily of a fixed monthly reservation fee based on eachshipper's maximum daily quantity and a commodity charge based onthe actual amount of gas transported.

With respect to KernRiver's original mainline facilities, Kern River entered into 27long-term firm gas transportation service agreements with 17 shippers,for a total of 864,154 Dth per day of capacity. All but one of theselong-term firm gas transportation service agreements expires on orbefore April 30, 2017. Several of these shippers are major oil and gascompanies, or affiliates of such companies. These shippers also includeelectric generating companies, energy marketing and trading companies,and a gas distribution utility which provides services in Nevada andCalifornia.

With respect to Kern River's 2003 ExpansionProject, Kern River entered into 19 long-term firm gas transportationservice agreements with 17 shippers, for a total of 906,626 Dth per dayof capacity from Opal, Wyoming to delivery points primarily inCalifornia, commencing May 1, 2003. Approximately 85% of thecapacity of the 2003 Expansion Project was contracted for 15 years,with 14 of the long-term firm gas transportation service agreementsexpiring on April 30, 2018. The remaining 15% of capacity wascontracted for 10 years, with five long-term firm gas transportationservice agreements expiring on April 30, 2013. Over 95% of thecapacity of the 2003 Expansion Project has primary delivery points inCalifornia, with the flexibility to access secondary delivery points inNevada and Utah.

Mirant Americas Energy Marketing("Mirant") was one of the shippers thatentered into a 15–year, 2003 Expansion Project, firm gastransportation contract (90,000 Dth per day) with Kern River (the"Mirant Agreement") and provided a letter ofcredit equivalent to 12 months of reservation charges as security forthe Mirant Agreement. In July 2003, Mirant filed for Chapter 11bankruptcy protection and continued to use the Mirant Agreementpost-bankruptcy. In October 2003, Mirant informed Kern River that itwould not renew its letter of credit and Kern River drew on the letterof credit and held the $14.8 million as cash collateral. EffectiveDecember 18, 2003, Mirant rejected the Mirant Agreement pursuant toprocedures under the Bankruptcy Code and paid all post-petition amountsowing under the Mirant Agreement through December 18, 2003. On January13, 2004, Kern River filed a proof of claim with the bankruptcy courtfor an aggregate total claim of $210.2 million, of which amount KernRiver believes it 

9

----

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

On May 1, 2003, Kern River Funding Corporation, a wholly ownedsubsidiary of Kern River, issued $836 million of its 4.893%Senior Notes with a final maturity on April 30, 2018. The proceeds wereused to repay all of the approximately $815 million of outstandingborrowings under Kern River's $875 million credit facilityentered into in 2002 to finance the construction of the 2003 ExpansionProject.

Northern Natural Gas

Business

Through Northern Natural Gas, MEHC owns one of the largestinterstate natural gas pipeline systems in the United States. Itreaches from Texas to Michigan's Upper Peninsula and is engagedin the transmission and storage of natural gas for utilities,municipalities, other pipeline companies, gas marketers, industrial andcommercial users and other end users. Northern Natural Gas operatesapproximately 16,500 miles of natural gas pipelines with a designcapacity of 4.4 Bcf per day. Based on a review of relevant industrydata, the Northern Natural Gas system is believed to be the largest inthe United States as measured by pipeline miles and the eighth largestas measured by throughput. Northern Natural Gas' revenue isderived from the interstate transportation and storage of natural gasfor third parties. Except for small quantities of natural gas owned forsystem operations, Northern Natural Gas does not own the natural gasthat is transported through its system. Northern Natural Gas'transportation and storage operations are subject to a Federal EnergyRegulatory Commission ("FERC") regulatedtariff that is designed to allow it an opportunity to recover its coststogether with a regulated return on equity.

Northern NaturalGas' system is comprised of two distinct but operationallyintegrated markets. Its traditional end-use and distribution marketarea is at the northern end of the system, including delivery points inMichigan, Illinois, Iowa, Minnesota, Nebraska, Wisconsin and SouthDakota, which Northern Natural Gas refers to as the Market Area, andthe natural gas supply and service area is at the southern end of thesystem, including Kansas, Oklahoma, Texas and New Mexico, whichNorthern Natural Gas refers to as the Field Area. Northern NaturalGas' Field Area is interconnected with many interstate andintrastate pipelines in the national grid system. A majority ofNorthern Natural Gas' capacity in both the Market Area and theField Area is dedicated to Market Area customers under long-term firmtransportation contracts. Approximately 73% of Northern NaturalGas' firm transportation contracts extend beyond 2006.

Northern Natural Gas' pipeline system transports natural gasprimarily to end-user and local distribution markets in the MarketArea. Customers consist of local distribution companies("LDCs"), municipalities, other pipelinecompanies, gas marketers and end-users. While approximately ten largeLDCs account for the majority of Market Area volumes, Northern NaturalGas also serves numerous small communities through these large LDCs aswell as municipalities or smaller LDCs and directly serves severallarge end-users. In 2003, approximately 85% of Northern NaturalGas' revenue was from capacity charges under firm transportationand storage contracts and approximately 81% of that revenue wasfrom LDCs. In 2003, approximately 70% of Northern NaturalGas' revenue was generated from Market Area customercontracts.

The Field Area of Northern Natural Gas' systemprovides access to natural gas supply from key production areasincluding the Hugoton, Permian and Anadarko Basins. In each of theseareas, Northern Natural Gas has numerous interconnecting receipt anddelivery points, with volumes received in the Field Area consisting ofboth directly connected supply and volumes from interconnections withother pipeline systems. In addition, Northern Natural Gas has theability to aggregate processable natural gas for deliveries to variousgas processing facilities.

In the Field Area, customers holdingtransportation capacity consist of LDCs, marketers, producers, andend-users. The majority of Northern Natural Gas' Field Area firmtransportation is provided to 

10

----

Northern Natural Gas' Market Area firmcustomers under long-term firm transportation contracts with suchvolumes supplemented by volumes transported on an interruptible basisor pursuant to short-term firm contracts. In 2003, approximately21% of Northern Natural Gas' revenue was generated fromField Area customer transportation contracts.

Northern NaturalGas' storage services are provided through the operation of oneunderground storage field in Iowa, two underground storage facilitiesin Kansas and one liquefied natural gas("LNG") storage peaking unit at each ofGarner, Iowa and Wrenshall, Minnesota. The three underground naturalgas storage facilities and Northern Natural Gas' two LNG storagepeaking units have a total working storage capacity of approximately 59Bcf and over 1.3 Bcf per day of peak day deliverability. These storagefacilities provide Northern Natural Gas with operational flexibilityfor the daily balancing of its system and providing services tocustomers for meeting their year-round loadswing requirements. In 2003,approximately 9% of Northern Natural Gas' revenue wasgenerated from storage services.

Northern Natural Gas'system is characterized by significant seasonal swings in demand, whichprovide opportunities to deliver high value-added services. Because ofits location and multiple interconnections with other interstate andintrastate pipelines, Northern Natural Gas is able to access naturalgas both from traditional production areas, such as the Hugoton,Permian and Anadarko Basins, as well as growing supply areas such asthe Rocky Mountains through Trailblazer Pipeline Company, Pony ExpressPipeline and Colorado Interstate Gas Pipeline Company("Colorado Interstate"), and from Canadianproduction areas through Northern Border, Great Lakes Gas TransmissionLimited Partnership ("Great Lakes") andViking Gas Transmission Company ("Viking").As a result of Northern Natural Gas' geographic location in themiddle of the United States and its many interconnections with otherpipelines, Northern Natural Gas augments its steady end-user and LDCrevenue by taking advantage of opportunities to provide intermediatetransportation through pipeline interconnections for customers in othermarkets including Chicago, Illinois, other parts of the Midwest andTexas.

Kern River and Northern Natural GasCompetition

Each of Kern River and Northern Natural Gas hasseveral customers who account for greater than 10% of itsrevenue. The loss of any one or more of these, if not replaced, couldhave a material adverse effect on Kern River and Northern NationalGas' respective businesses.

Pipelines compete on the basisof cost (including both transportation costs and the relative costs ofthe natural gas they transport), flexibility, reliability of serviceand overall customer service. Industrial end-users often have theability to choose from alternative fuel sources in addition to naturalgas, such as fuel oil and coal. Natural gas competes with other formsof energy, including electricity, coal and fuel oil, primarily on thebasis of price. Legislation and governmental regulations, the weather,the futures market, production costs, and other factors beyond thecontrol of Kern River and Northern Natural Gas influence the price ofnatural gas.

Kern River competes with various interstatepipelines and its shippers in serving the southern California, LasVegas, Nevada and Salt Lake City, Utah market areas, in order to marketany unutilized or unsubscribed capacity. Kern River provides itscustomers with supply diversity through pipeline interconnections withNorthwest Pipeline, Colorado Interstate, Overland Trail Pipeline, andQuestar Pipeline. These interconnections, in addition to the directinterconnections to natural gas processing facilities, allow Kern Riverto access natural gas reserves in Colorado, northwestern New Mexico,Wyoming, Utah and the Western Canadian Sedimentary Basin.

KernRiver is the only interstate pipeline that presently delivers naturalgas directly from a gas supply basin into the intrastate Californiamarket, which enables its customers to avoid paying a"rate stack" (i.e., additional transportationcosts attributable to the movement from one or more interstate pipelinesystems to an intrastate system within California). Kern River believesthat its rate structure and access to upstream pipelines/storagefacilities and to economic Rocky Mountain gas reserves increases itscompetitiveness and attractiveness to end-users. Kern River believes itis advantaged relative to other competing interstate pipelines becauseits relatively new pipeline can be expanded at comparatively lowercosts and will require significantly less capital expenditure to complywith the Pipeline Safety Improvement Act of 2002 (the"Pipeline Safety Improvement Act") than othersystems. Kern River's levelized 

11

----

rate structures under expansion rates andsettlement 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 theRocky Mountain area, an area that in recent years has attractedconsiderable expansion of pipeline capacity serving markets other thanCalifornia and Nevada. In addition, Kern River's 2003 ExpansionProject relies substantially on long-term transportation serviceagreements with several electric generation companies, who facesignificant competitive and financial pressures due to, among otherthings, the financial stress of energy markets and apparentover-building of electric generation capacity in California and othermarkets.

Northern Natural Gas has been able to providecompetitive cost service because of its access to a variety ofrelatively low cost gas supply basins, its cost control measures andits relatively high load factor throughput, which lowers the cost perunit of transportation. Although Northern Natural Gas has experiencedpipeline system bypass affecting a small percentage of its market, todate Northern Natural Gas has been able to more than offset any loadlost to bypass in the Northern Natural Gas Market Area throughexpansion projects.

Major competitors in the Northern NaturalGas 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 NorthernNatural Gas' capacity is used on an interruptible or short-termbasis. In summer months, Northern Natural Gas' Market Areacustomers often release significant amounts of their unused firmcapacity to other shippers, which released capacity competes withNorthern Natural Gas' short-term or interruptible services.

Although Northern Natural Gas will need to aggressively compete toretain and build load, Northern Natural Gas believes that current andanticipated changes in its competitive environment have createdopportunities to serve existing customers more efficiently and to meetcertain growing supply needs. While LDCs peak day growth is driven bypopulation growth and alternative fuel replacement, new off-peak demandgrowth is being driven primarily by power and ethanol plant expansion.Off-peak demand growth is important to Northern Natural Gas as thisdemand can generally be satisfied with little or no requirement for theconstruction of new facilities. Northern Natural Gas has beensuccessful in competing for a significant amount of the increaseddemand related to the construction of new power and ethanol plants.Over the last five years, Northern Natural Gas has contractedapproximately 480 mmcf per day of volume on its system from such newfacilities, of which approximately 465 mmcf per day is currently inservice and approximately 15 mmcf per day is scheduled to begin servicein 2004.

Pipeline Development Project

On January 22,2004, MEHC and a recently formed subsidiary, Alaska Gas TransmissionCompany, LLC ("Alaska Gas"), filed anapplication with the State of Alaska Department of Revenue for approvalunder the Alaska Stranded Gas Development Act("ASGDA") for authority to negotiate tax andfinancial terms with the State of Alaska to facilitate thetransportation of stranded Alaskan natural gas. The proposed 745-mile,$6.3 billion pipeline, would be subject to FERC regulation and wouldextend from the North Slope area near Prudhoe Bay, Alaska southward tothe Alaska-Yukon border near Beaver Creek, Alaska. On January 28, 2004,MEHC and Alaska Gas received notification from the Office of theCommissioner of the Department of Revenue of the State of Alaska thatthe proposed Alaska pipeline is a qualified project and Alaska Gas andits constituent owner-members constitute a qualified sponsor group,qualified to negotiate for favorable tax and financial terms as allowedunder the ASGDA. MEHC, Alaska Gas, and two unaffiliated parties holdingrights to acquire up to a combined aggregate of 19.9% of AlaskaGas's economic interest, intend to promptly commence negotiationswith the State of Alaska.

12

----

CE Electric UK

Business

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

In December1996, CE Electric UK Ltd., an indirect wholly owned subsidiary of CEElectric UK, acquired Northern Electric. Northern Electric was one ofthe fifteen original United Kingdom regional electric companies thatcame into existence in 1990 as a result of the restructuring andsubsequent privatization of the electricity industry that occurred inthe United Kingdom. In September 2001, CE Electric UK acquired94.75% of Yorkshire from Innogy Holdings plc("Innogy") and simultaneously sold NorthernElectric's electricity and gas supply and metering businesses toInnogy. The Company sometimes refers to these transactions as the"Yorkshire Swap". In August 2002, CE ElectricUK acquired the remaining 5.25% of Yorkshire that it did notalready own from Xcel Energy International("Xcel"), an affiliate of Xcel EnergyInc.

With the acquisition of Yorkshire, CE Electric UK is one ofthe largest distribution companies in the United Kingdom, serving morethan 3.7 million customers in an area of approximately 10,000 squaremiles.

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

ElectricityDistribution

Northern Electric's andYorkshire's operations consist primarily of the distribution ofelectricity in the United Kingdom. Northern Electric's andYorkshire's distribution licensee companies, NED and YED,respectively, receive electricity from the national grid transmissionsystem and distribute it to their customers' premises using theirnetwork of transformers, switchgear and cables. Substantially all ofthe end users in NED's and YED's distribution service areasare connected to the NED and YED networks and electricity can only bedelivered through their distribution system, thus providing NED and YEDwith distribution volume that is relatively stable from year to year.NED and YED charge fees for the use of the distribution system to thesuppliers of electricity. The suppliers, which purchase electricityfrom generators and sell the electricity to end-user customers, useNED's and YED's distribution networks pursuant to anindustry standard "Use of System Agreement"which NED and YED separately entered into with the various suppliers ofelectricity in their respective distribution areas. One such supplier,Innogy plc. and certain of its affiliates, represented approximately50% of the total revenues of NED and YED in 2003. The fees thatmay be charged by NED and YED for use of their distribution systems arecontrolled by a formula prescribed by the UK's electricityregulatory body that limits increases (and may require decreases) basedupon the rate of inflation in the United Kingdom and other regulatoryaction.

At December 31, 2003, NED's and YED'selectricity distribution network (excluding service connections toconsumers) on a combined basis included approximately 31,000 kilometersof overhead lines and approximately 63,000 kilometers of undergroundcables. In addition to the circuits referred to above, at December 31,2003, NED's and YED's distribution facilities also includedapproximately 57,000 transformers and approximately 750 primarysubstations. Substantially all substations are owned, with the balancebeing leased from third parties, most of which have remaining terms ofat least 10 years.

Utility Services

IntegratedUtility Services Limited ("IUS"), asubsidiary of Northern Electric, is an engineering contracting companywhose main business is providing electrical connection services onbehalf of NED's and YED's distribution businesses andproviding electrical infrastructure contracting services to thirdparties.

Gas Exploration and Production

CalEnergy Gas (Holdings) Limited ("CEGas"), CE Electric UK's indirect subsidiary, is agas exploration and production company that is focused on developingintegrated upstream gas projects. Its 

13

----

upstream gas business consists of theexploration, development and production, including transportation andstorage, of gas for delivery to a point of sale into either a gassupply market or a power generation facility.

In May 2002, CEGas completed the sale of substantially all of its United Kingdomnatural gas assets to Gaz de France. In July 2003, CE Gas sold the ETSpipeline, which is a gas pipeline that extends from the North Sea togas terminals in the United Kingdom, assets to CH4 Energy Limited. CEGas retained its interest in the Victor Field, which is a gas fieldlocated in the North Sea. CE Gas also retained development interests inits Polish Trough project in Poland and its Bass, Otway and PerthBasins projects in Australia. In Poland, CE Gas, together with itsjoint venture partners FX Energy and the Polish Oil and Gas Company, iscurrently involved in drilling the Zaniemysl #3 well in the FencesConcession. The Bass development is a gas and gas liquids project inwhich CE Gas holds a 20% interest. The project, operated byOrigin Energy of Australia, is under construction and includes anapproximately 145 kilometer subsea pipeline across the Bass Strait offsouthern Victoria. The Bass project is expected to be fully operationalduring the fourth quarter of 2004. The gas from the project will besold to Origin Energy's retail affiliate and the liquids toElgas, the largest marketer of liquefied petroleum gas("LPG") in Australia. The Otway project, inwhich CE Gas holds a 6% interest and which is operated by anunaffiliated party, is expected to receive construction approval during2004 and offtake arrangements are being negotiated. In 2003, CE Gasacquired a one-third interest in Block LO2-6 in the northern PerthBasin, which is adjacent to the Dongara gas field. Arc Energy andNorwest Energy each also hold a one-third interest. The new permit issubject to satisfaction of the native title process, which is ongoingand expected to be completed by late 2004, at which time explorationactivities can commence. In May 2003, CE Gas withdrew from all itssouthern Perth Basin permits.

CalEnergy Generation –Domestic

Business

Through CalEnergy Generation– Domestic, the Company owns interests in 15 operatingnon-utility power projects in the United States. The following tablesets out certain information concerning CalEnergy Generation– Domestic's non-utility power projects in operationas of December 31, 2003:

|                           |  |                            |        |                |  |        |        |          |  |                                  |        |                   |  |        |            |        |  |        |        |        |  |                           |  |  |  |  |
|---------------------------|--|----------------------------|--------|----------------|--|--------|--------|----------|--|----------------------------------|--------|-------------------|--|--------|------------|--------|--|--------|--------|--------|--|---------------------------|--|--|--|--|
| OperatingProject          |  | FacilityNetCapacity(MW)(1) |        | Net MWOwned(1) |  | Fuel   |        | Location |  | PowerPurchaseAgreementExpiration |        | PowerPurchaser(2) |
| Cordova                   |  |                       | 537    |           |  |   | 537    |     |  |                             | Gas    |              |  |   | Illinois   |   |  |   | 2017   |   |  | ElPaso/MidAmerican Energy |
| Salton SeaI               |  |                       | 10     |           |  |   | 5      |     |  |                             | Geo    |              |  |   | California |   |  |   | 2017   |   |  | Edison                    |
| SaltonSeaII               |  |                       | 20     |           |  |   | 10     |     |  |                             | Geo    |              |  |   | California |   |  |   | 2020   |   |  | Edison                    |
| SaltonSeaIII              |  |                       | 50     |           |  |   | 25     |     |  |                             | Geo    |              |  |   | California |   |  |   | 2019   |   |  | Edison                    |
| SaltonSeaIV               |  |                       | 40     |           |  |   | 20     |     |  |                             | Geo    |              |  |   | California |   |  |   | 2026   |   |  | Edison                    |
| SaltonSeaV                |  |                       | 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                    |
| DelRanch                  |  |                       | 38     |           |  |   | 19     |     |  |                             | Geo    |              |  |   | California |   |  |   | 2019   |   |  | Edison                    |
| CETurbo                   |  |                       | 10     |           |  |   | 5      |     |  |                             | Geo    |              |  |   | California |   |  |   | Varies |   |  | TransAlta/Minerals(3)     |
| Saranac                   |  |                       | 240    |           |  |   | 90     |     |  |                             | Gas    |              |  |   | NewYork    |   |  |   | 2009   |   |  | NYSE&G                |
| PowerResources(4)         |  |                       | 212    |           |  |   | 106    |     |  |                             | Gas    |              |  |   | Texas      |   |  |   | 2005   |   |  | ONEOK                     |
| Yuma                      |  |                       | 50     |           |  |   | 25     |     |  |                             | Gas    |              |  |   | Arizona    |   |  |   | 2024   |   |  | SDG&E                 |
| RooseveltHotSprings(5)    |  |                       | 23     |           |  |   | 17     |     |  |                             | Geo    |              |  |   | Utah       |   |  |   | 2020   |   |  | UP&L                  |
| DomesticOperatingProjects |  |                       | 1,389  |           |  |   | 939    |     |  |                             |   |              |  |   |       |   |  |   |   |   |  |                      |
|                           |

|           |                                                                                                                                                                                                                                                                                                                 |
|-----------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (1)  | Representsnominal net generating capability (accredited for Cordova and contractfor most others). Actual MW may vary depending on operating conditionsand plant design. Net MW owned indicates current legal ownership, but,in some cases, does not reflect the current allocation of partnershipdistributions. |

14

----

|           |                                                                                                                                                                                                                                                                                                                                                                                                                              |
|-----------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2)  | El PasoCorporation ("El Paso"); Southern CaliforniaEdison Company ("Edison"); TransAlta USA Inc.("TransAlta"); CalEnergy Minerals LLC("Minerals"); the City of Riverside,California ("Riverside"); New York StateElectric & Gas Corporation("NYSE&G"); ONEOK Energy, Marketing andTrading Company, L.P. ("ONEOK"); San DiegoGas & Electric Company ("SDG&E"); andUtah Power & Light Company("UP&L"). |

|           |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|-----------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (3)  | Eachcontract governing power purchases by Minerals will expire 33 yearsfrom the date of the initial power delivery under such contract.Pursuant to a Transaction Agreement dated January 29, 2003, Salton SeaPower LLC ("Salton Sea Power") which ownsSalton Sea V, and CE Turbo LLC ("CE Turbo")began selling available power to a subsidiary of TransAlta on February12, 2003 based on percentages of the Dow Jones SP-15 Index. TheTransaction Agreement shall continue until the earlier of (a) 30 daysfollowing a written notice of termination or (b) any other terminationdate mutually agreed to by the parties. No such notice of terminationhas been given by either party. Effective July 1, 2004, Salton SeaPower and CE Turbo will also be selling the environmental attributesassociated with up to 931,800 MWh to TransAlta Energy Marketing (US)Inc., an affiliate of TransAlta, through December 31, 2008. Salton SeaPower also entered into a 10-year power sales agreement for up to 20 MWwith Riverside in May 2003. |

|           |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
|-----------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (4)  | PowerResources net capacity was 200 MW during operation as a qualifyingfacility ("QF") within the meaning of thePublic Utility Regulatory Policies Act of 1978, as amended("PURPA") under the TXU Power GenerationCompany, LP ("TXU") Power Purchase Agreement,which expired September 30, 2003. The net capacity increased to 212 MWduring operations as an exempt wholesale generator("EWG"), as defined by the Energy Policy Actof 1992, under the ONEOK tolling agreement due to the absence of theneed to deliver steam to a third party. |

|           |                                                                                                                                                                                                                                                                                                                                                           |
|-----------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (5)  | Intermountain Geothermal Company, anindirect subsidiary of MEHC, owns an approximately 70% indirectinterest in this project which supplies geothermal steam to a powerplant owned by UP&L. The Company obtained a cash prepayment under apre-sale agreement with UP&L whereby UP&L paid in advance forthe steam produced by this steam field. |

Cordova Energy owns a537 MW gas-fired power plant in the Quad Cities, Illinois area (the"Cordova Project"). CalEnergy GenerationOperating Company, an indirect wholly owned subsidiary of MEHC,operates the Cordova Project which commenced commercial operations inJune 2001. Cordova Energy entered into a power purchase agreement witha unit of El Paso, under which El Paso will purchase all of thecapacity and energy from the project until December 31, 2019. CordovaEnergy has exercised an option to recall from El Paso 50% of theoutput through May 14, 2004, reducing El Paso's purchaseobligation to 50% of the output during such period. The recalledoutput is being sold to MidAmerican Energy. The Company is aware therehave been public announcements that El Paso's financial conditionhas deteriorated as a result of, among other things, reduced liquidityand will continue to monitor the situation.

MEHC has a50% ownership interest in CE Generation, LLC ("CEGeneration") whose affiliates currently operate tengeothermal plants in the Imperial Valley in California (the"Imperial Valley Projects"). The ImperialValley Projects include the "Salton SeaProjects" 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 theVulcan, Elmore, Leathers, Del Ranch and CE Turbo projects.

Eachof the Imperial Valley Projects, excluding the Salton Sea V and CETurbo projects, sells electricity to Edison pursuant to a separateStandard Offer No. 4 Agreement ("SO4Agreement") or a negotiated power purchase agreement. Eachpower purchase agreement is independent of the others, and theperformance requirements specified within one such agreement apply onlyto the project, which is subject to the agreement. The power purchaseagreements provide for energy payments, capacity payments and capacitybonus payments. Edison makes fixed annual capacity payments andcapacity bonus payments to the applicable projects to the extent thatcapacity factors exceed certain benchmarks. The price for capacity wasfixed for the life of the SO4 Agreements and is significantly higher inthe months of June through September.

Energy payments for theSO4 Agreements were at increasing fixed rates for the first ten yearsafter firm operation and thereafter at a rate based on the cost thatEdison avoids by purchasing energy from 

15

----

the project instead of obtaining the energyfrom other sources ("Avoided Cost ofEnergy"). In June and November 2001, the Imperial ValleyProjects (except the Salton Sea IV, Salton Sea V and CE Turbo projects)which receive Edison's Avoided Cost of Energy, entered intoagreements that provide for amended energy payments under the SO4Agreements. The amendments provide for fixed energy payments per kWh inlieu of Edison's Avoided Cost of Energy. The fixed energy paymentwas 3.25 cents per kWh from December 1, 2001 through April 30, 2002 andis 5.37 cents per kWh commencing May 1, 2002 for a five-year period.Following the five-year period, the energy payments revert back toEdison's Avoided Cost of Energy.

For the years endedDecember 31, 2003, 2002 and 2001, respectively, Edison's AverageAvoided Cost of Energy was 5.4 cents per kWh, 3.5 cents per kWh and 7.4cents per kWh, respectively. Estimates of Edison's future AvoidedCost of Energy vary substantially from year to year.

The SaltonSea 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-yearpower sales agreement. The agreement provides for energy payments basedon the market rates available to the Salton Sea V project, adjusted forwheeling costs. On May 20, 2003, Salton Sea Power entered into a powersales agreement with Riverside. Under the terms of the agreement,Salton Sea Power sells up to 20 MW of energy generated from the SaltonSea V project to Riverside. Sales under the agreement commenced June 1,2003 and will terminate May 31, 2013. The Salton Sea V project sellsits remaining output through other market transactions.

The CETurbo project, which commenced commercial operation in the thirdquarter of 2000, sells its output through market transactions. The CETurbo project may sell its output to Minerals, pursuant to a 33-yearpower purchase agreement. The agreement provides for energy paymentsbased on the market rates available to the CE Turbo project, adjustedfor wheeling costs.

Salton Sea Power and CE Turbo began sellingpower to a subsidiary of TransAlta on February 12, 2003 based onpercentages of Dow Jones SP-15 Index. The Transaction Agreement shallcontinue until the earlier of (a) 30 days following a written notice oftermination by either party or (b) any other termination date mutuallyagreed to by the parties. No such notice of termination has been givenby either party.

The Saranac project is a 240 net MW naturalgas-fired cogeneration facility located in Plattsburgh, New York ownedby the Saranac Partnership which is indirectly owned by subsidiaries ofCE Generation, ArcLight Capital Holdings and General Electric CapitalCorporation. The Saranac project has entered into a 15-year powerpurchase agreement with NYSE&G, 15-year steam purchase agreementswith Georgia-Pacific Corporation and Pactiv Corporation and a 15-yearnatural gas supply contract with Coral Energy to supply 100% ofthe Saranac project's fuel requirements. The power purchaseagreement, the steam purchase agreement and the gas supply agreementcontain rates that are fixed for the respective contract terms andexpire in 2009.

The Power Resources project, a 212 net MWnatural gas-fired cogeneration project owned by Power Resources Ltd.("Power Resources"), an indirect wholly-ownedsubsidiary of CE Generation, sold electricity to TXU, as a QF underPURPA, pursuant to a power purchase agreement which expired onSeptember 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 Agreementwith ONEOK. The agreement commenced October 1, 2003 and expiresDecember 31, 2005. Under the terms of the agreement, Power Resources,as an EWG, sells its energy and capacity to ONEOK for a fixed amountper kW-month plus a variable operating and maintenance fee per MWh. Inaddition, ONEOK pays annual turbine start-up costs.

The Yumaproject is a 50 net MW natural gas-fired cogeneration project in Yuma,Arizona providing 50 MW of electricity to SDG&E under an existing30-year power purchase contract commencing in May 1994. The projectentity, Yuma Cogeneration Associates, has executed steam salescontracts with Queen Carpet, Inc. to act as its thermal host.

The Roosevelt Hot Springs project is a geothermal steam field whichsupplies geothermal steam to a 23 net MW power plant owned by UP&Llocated on the Roosevelt Hot Springs property under a 

16

----

30-year steam sales contract expiring in2020. The Company obtained a cash prepayment under a pre-sale agreementwith UP&L whereby UP&L paid in advance for the steam producedby the steam field. MEHC guarantees the performance of this subsidiaryand must make certain penalty payments to UP&L if the steamproduced does not meet certain quantity and quality requirements.

Zinc Recovery Project

MEHC's indirectly whollyowned subsidiary, Minerals, developed and owns the rights toproprietary processes for the extraction of zinc from elements insolution in the geothermal brine and fluids utilized at the ImperialValley Projects. The affiliates of Minerals may develop facilities forthe extraction of manganese, silica and other products as they furtherdevelop the extraction technology.

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

DevelopmentProjects

MEHC's subsidiary, CE Obsidian Energy LLC("Obsidian"), is evaluating the developmentof a 185 net MW geothermal facility in the Imperial Valley inCalifornia. Substantially all of the output of the facility would besold to the Imperial Irrigation District("IID") pursuant to a power purchaseagreement. TransAlta is currently funding 50% of the developmentcosts of this project. On December 17, 2003, the California EnergyCommission ("CEC") gave final approval forconstruction of the facility.

CalEnergy Generation –Foreign

Business

The CalEnergy Generation – Foreignplatform consists of MEHC's indirect ownership of the UpperMahiao, Malitbog and Mahanagdong projects, which are geothermal powerplants located on the island of Leyte in the Philippines, and theCasecnan project, a combined irrigation and hydroelectric powergeneration project located in the central part of the island of Luzonin the Philippines. Each plant possesses an operating margin thatallows for production in excess of the amount listed below. Utilizationof this operating margin is based upon a variety of factors and can beexpected to vary between calendar quarters under normal operatingconditions.

The following table sets out certain informationconcerning CalEnergy Generation – Foreign's non-utilitypower projects in operation as of December 31, 2003:

|                       |  |                             |     |               |  |        |     |                     |  |                             |        |        |  |        |         |        |  |        |              |        |  |  |
|-----------------------|--|-----------------------------|-----|---------------|--|--------|-----|---------------------|--|-----------------------------|--------|--------|--|--------|---------|--------|--|--------|--------------|--------|--|--|
| Project(1)            |  | FacilityNet Capacity(MW)(2) |     | NetMWOwned(2) |  | Fuel   |     | CommercialOperation |  | PowerPurchaser/Guarantor(3) |
| UpperMahiao           |  |                        | 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      |   |
| InternationalProjects |  |                        | 640 |          |  |   | 635 |                |  |                        |   |   |  |   |    |   |  |   |         |   |
|                       |

|           |                                                                                                                                                                             |
|-----------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (1)  | Allprojects are located in the Philippines; all projects are governed bycontracts which are mainly payable in U.S. dollars; and all projectscarry political risk insurance. |

|           |                                                                                                                                                                                                                                                                                                                            |
|-----------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2)  | Actual MW may vary depending onoperating, geothermal reservoir and water flow conditions, as well asplant design. Facility Net Capacity (MW) represents the contractcapacity for the facility. Net MW Owned indicates current legalownership, but, in some cases, does not reflect the current allocationof distributions. |

17

----

|           |                                                                                                                                                                                                                                                                                                                                                                                                                                                |
|-----------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (3)  | Philippine National Oil Company-Energy Development Corporation("PNOC-EDC"), Republic of the Philippines("ROP"), and National IrrigationAdministration ("NIA"). NIA also pays CECasecnan Water and Energy Company, Inc. ("CECasecnan"), an indirect subsidiary of MEHC, for thedelivery of water and electricity by CE Casecnan. Separate sovereignundertakings of the ROP for each project support PNOC-EDC's andNIA's respective obligations. |

|           |                                                                                                                                                                                                                                                                                                                                             |
|-----------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (4)  | Net MW Owned, of approximately 150 MW,is subject to repurchase rights of up to 15% of the project byan initial minority shareholder and a dispute with the other initialminority shareholder regarding an additional 15% of the project.Refer to "Item 3. Legal Proceedings — Philippines— CE Casecnan Stockholder Litigation." |

TheUpper Mahiao project is a 119 net MW geothermal power project owned andoperated by CE Cebu Geothermal Power Company, Inc. ("CECebu"), a Philippine corporation that is 100%indirectly owned by the MEHC. On June 18, 2006, the end of the ten-yearcooperation period, the Upper Mahiao facility will be transferred toPNOC-EDC at no cost on an "as-is" basis.

The Upper Mahiao project takes geothermal steam and fluid, providedby PNOC-EDC at no cost, and converts its thermal energy into electricalenergy which is sold to PNOC-EDC on a"take-or-pay" basis, which in turn sells thepower to the National Power Corporation, the government-owned andcontrolled corporation that is the primary supplier of electricity inthe Philippines ("NPC"), for distribution onthe island of Cebu. PNOC-EDC pays CE Cebu a fee based on the plantcapacity. Pursuant to an amendment to the Upper Mahiao energyconversion agreement entered into on August 31, 2003, CE Cebu andPNOC-EDC agreed that the plant capacity for purposes of the fee wouldequal the contractually specified level of 118.5 MW. PNOC-EDC also paysCE Cebu a fee based on the electricity actually delivered to PNOC-EDC(approximately 5% of total contract revenue). Payments under theUpper Mahiao agreement are denominated in U.S. dollars, or computed inU.S. dollars and paid in pesos at the then-current exchange rate,except for the energy fee. PNOC-EDC's payment requirements, andits other obligations under the Upper Mahiao agreement, are supportedby the ROP through a performance undertaking.

The Mahanagdongproject is a 155 net MW geothermal power project owned and operated byCE Luzon Geothermal Power Company, Inc. ("CELuzon"), a Philippine corporation of which MEHC indirectlyowns 100% of the common stock. Another industrial company ownsan approximate 3% preferred equity interest in the MahanagdongProject. The Mahanagdong project sells 100% of its capacity toPNOC-EDC, which in turn sells the power to the NPC for distribution onthe island of Luzon.

The terms of the Mahanagdong energyconversion agreement are substantially similar to those of the UpperMahiao agreement. On July 25, 2007, the end of the ten year cooperationperiod, the Mahanagdong facility will be transferred to PNOC-EDC at nocost on an "as-is" basis. PNOC-EDC pays CELuzon a fee based on the plant capacity. Pursuant to an amendment tothe Mahanagdong energy conversion agreement entered into onAugust  31, 2003, CE Luzon and PNOC-EDC agreed that the plantcapacity would equal the contractually specified level, which declinesfrom approximately 155 MW in 2004 to approximately 153 MW in the lastyear of the cooperation period. The capacity fees are approximately97% of total revenue at the contractually agreed capacity levelsand the energy fees are approximately 3% of such total revenue.PNOC-EDC's payment requirements, and its other obligations underthe Mahanagdong agreement, are supported by the ROP through aperformance undertaking.

The Malitbog project is a 216 net MWgeothermal project owned and operated by Visayas Geothermal PowerCompany ("VGPC"), a Philippine generalpartnership that is indirectly wholly owned by MEHC. VGPC sells100% of its capacity on substantially the same basis asdescribed above for the Upper Mahiao project to PNOC-EDC, which sellsthe power to the NPC for distribution on the islands of Cebu andLuzon.

The electrical energy produced by the facility is sold toPNOC-EDC on a "take-or-pay" basis. Thesecapacity payments equal approximately 100% of total revenue.Pursuant to an amendment to the Malitbog energy conversion agreemententered into on August 31, 2003, VGPC and PNOC-EDC agreed that theplant capacity would equal the contractually specified level of 216 MW.A substantial majority of the capacity payments are required to be madeby PNOC-EDC in U. S. dollars. The portion of capacity 

18

----

payments payable to PNOC-EDC in pesos isexpected to vary over the term of the Malitbog project energyconversion agreement from 10% of VGPC's revenue in theearly years of the cooperation period to 23% of VGPC'srevenue at the end of the cooperation period. Payments made in pesoswill generally be made to a peso-dominated account and will be used topay peso-denominated operation and maintenance expenses with respect tothe Malitbog project and Philippine withholding taxes, if any, on theMalitbog project's debt service. The government of thePhilippines has entered into a performance undertaking, which providesthat all of PNOC-EDC's obligations pursuant to the Malitbogenergy conversion agreement carry the full faith and credit of, and areaffirmed and guaranteed by, the ROP. The Malitbog energy conversionagreement ten year cooperation period expires on July 25, 2007, atwhich time the facility will be transferred to PNOC-EDC at no cost, onan "as is" basis.

CE Casecnan owns andoperates the Casecnan project, a combined irrigation and hydroelectricpower generation project. The Casecnan project consists generally ofdiversion structures in the Casecnan and Taan rivers that capture anddivert excess water in the Casecnan watershed by means of concrete,in-stream diversion weirs and transfer that water through a transbasintunnel of approximately 23 kilometers. During the water transfer, theelevation differences between the two watersheds allows electricalenergy to be generated at an approximately 150 MW rated capacity powerplant, which is located in an underground powerhouse cavern at the endof the water tunnel. A tailrace discharge tunnel delivers water to thePantabangan reservoir, providing additional water for irrigation andincreasing the potential electrical generation at two existingdownstream hydroelectric facilities of NPC. Once in the reservoir atPantabangan, the water is under the control of NIA.

CE Casecnanowns and operates the Casecnan project under the terms of the ProjectAgreement between CE Casecnan and NIA, which was amended by aSupplemental Agreement between CE Casecnan and NIA signed in September2003 and effective on October 15, 2003 (the "SupplementalAgreement"). CE Casecnan will own and operate the projectfor a 20-year Cooperation Period which commenced on December 11,2001.

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

On October 15, 2003, pursuantto the Supplemental Agreement, all claims by CE Casecnan andcounterclaims by NIA in the NIA Arbitration were dismissed withprejudice and the terms of the Project Agreement were modified andsupplemented in certain respects. Summarized below are significantprovisions of the Project Agreement as supplemented by the SupplementalAgreement.

Under the Project Agreement, CE Casecnan is paid afee for the delivery of water and a fee for the generation ofelectricity. With respect to water deliveries, NIA is obligated to payCE Casecnan an amount for the delivery of water equal to the sum of theGuaranteed Water Delivery Fee plus the Variable Delivered WaterDelivery Fee minus the Water Delivery Fee Credit. For the sixty-monthperiod from December 25, 2003 through December 25, 2008, the GuaranteedWater Delivery Fee shall equal $0.029 per cubic meter, escalated at7.5% annually from January 1, 1994 through December 25, 2006(the "Guaranteed Water Delivery Rate")multiplied by approximately 66.8 million cubic meters per month(corresponding to the 801.9 million cubic meters per year), regardlessof actual water deliveries made by the Casecnan project. For each monthbeginning after December 25, 2008 through the remainder of theCooperation Period, the Guaranteed Water Delivery Fee shall equal theGuaranteed Water Delivery 

19

----

Rate multiplied by approximately 58.3million cubic meters (corresponding to 700.0 million cubic meters peryear), regardless of actual water deliveries made by the Casecnanproject.

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

The Water Delivery Credit shall be applicable only for each of thesixty-months from December 25, 2008 through December 25, 2013 and shallequal the Water Delivery Rate as of December 25, 2008 multiplied by thesum of each Annual Water Credit divided by sixty. The Annual WaterCredit for each contract year starting from December 25, 2003 andending on December 25, 2008 shall equal 801.9 million cubic metersminus the Total Available Water for each contract year. The TotalAvailable Water in any such year will equal actual deliveries with aminimum threshold of 700.0 million cubic meters.

With respect toelectricity, CE Casecnan is paid a Guaranteed Energy Delivery Fee eachmonth equal to the product obtained by multiplying 19,000,000 kWh times$0.1596 per kWh. The Guaranteed Energy Delivery Fee is payableregardless of the amount of energy actually generated and delivered byCE Casecnan in any month. NIA also pays CE Casecnan an Excess EnergyDelivery Fee, which is a variable amount based on actual electricalenergy, if any, delivered in each month in excess of 19,000,000 kWhmultiplied by (i) $0.1509 per kWh through the end of 2008 and (ii)commencing in 2009, $0.1132 (escalating at 1% per annumthereafter) per kWh, provided that any deliveries of energy in excessof 490,000,000 kWh but less than 550,000,000 kWh per year are paid forat a rate of 1.3 Philippine pesos per kWh and deliveries in excess of550 GWh per year are at no cost to NIA. If the Casecnan project is notdispatched up to 150 MW whenever water is available, NIA will pay forenergy that could have been generated but was not as a result of suchdispatch constraint.

The ROP has provided a PerformanceUndertaking under which NIA's obligations under the ProjectAgreement, as supplemented by the Supplemental Agreement, areguaranteed by the full faith and credit of the ROP. The ProjectAgreement and the Performance Undertaking provide for the resolution ofdisputes by binding arbitration in Singapore under internationalarbitration rules.

In connection with entering into theSupplemental Agreement, on October 15, 2003, NIA paid to CE Casecnanthe sum of $17.7 million plus 39.9 million pesos (approximately $0.7million) and delivered to CE Casecnan the ROP $97.0 million8.375% Note due 2013 (the "ROP Note"),which contained a put provision granting CE Casecnan the right to putthe ROP Note to the ROP for a price of par plus accrued interest for a30-day period commencing on January 14, 2004. Also pursuant to theSupplemental Agreement, CE Casecnan paid to the Philippine Bureau ofInternal Revenue ("BIR") approximately $24.4million in respect of Philippine income taxes on the foregoingconsideration and CE Casecnan paid to NIA $1.6 million in respect ofalleged late completion of the Casecnan project.

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

As part of thesettlement of the NIA Arbitration, CE Casecnan also received writtenconfirmation from the Private Sector Assets and Liabilities ManagementCorporation that the issues with respect to the Casecnan project thathad been raised by the interagency review of independent powerproducers in the Philippines or that may have existed with respect tothe project under certain provisions of the Electric Power IndustryReform Act of 2001, which authorized the ROP to seek to renegotiatecertain contracts such as the Project Agreement, have beensatisfactorily addressed by the Supplemental Agreement.

20

----

HomeServices

Business

HomeServices is the second largestfull-service residential real estate brokerage firm in the UnitedStates. In addition to providing traditional residential real estatebrokerage services, HomeServices offers other integrated real estateservices, including mortgage originations, title and closing servicesand other related services. HomeServices currently operates in 16states under the following brand names: Carol Jones REALTORS, CBSHOMEReal Estate, Champion Realty, Edina Realty Home Services,Esslinger-Wooten-Maxwell REALTORS, First Realty/GMAC, HOME Real Estate,Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty,Prudential California Realty, RealtySouth, Rector-Hayden REALTORS,Reece & Nichols, Semonin REALTORS and Woods Bros. Realty.HomeServices generally occupies the number one or number two marketshare position in each of its major markets based on aggregate closedtransaction sides. HomeServices' major markets consist of thefollowing metropolitan areas: Minneapolis and St. Paul, Minnesota; LosAngeles 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 anaggregate purchase price of approximately $36.7 million, net of cashacquired, plus working capital and certain other adjustments. For theyear ended December 31, 2002, these real estate companies had combinedrevenue of approximately $102.9 million on 16,000 closed sidesrepresenting $3.6 billion of sales volume. In 2002, HomeServicesseparately acquired three real estate companies for an aggregatepurchase price of approximately $106.1 million, net of cash acquired,plus working capital and certain other adjustments. For the year endedDecember 31, 2001, these real estate companies had combined revenue ofapproximately $356.0 million on 42,000 closed sides representing $13.7billion of sales volume.

Regulatory Matters

GeneralRegulation

The Company's operating platforms are subjectto a number of federal, state, local and international regulations.

MidAmerican Energy

MidAmerican Energy is subject tocomprehensive regulation by the FERC as well as utility regulatoryagencies in Iowa, Illinois and South Dakota that significantlyinfluences the operating environment and the recoverability of costsfrom utility customers. Except for Illinois, that regulatoryenvironment has to date, in general, given MidAmerican Energy anexclusive right to serve electricity customers within its serviceterritory and, in turn, the obligation to provide electric service tothose customers. In Illinois all customers are free to choose theirelectricity provider. MidAmerican Energy has an obligation to servecustomers at regulated rates that leave MidAmerican Energy'ssystem, but later choose to return. To date, there has been nosignificant loss of customers from MidAmerican Energy's existingregulated Illinois rates.

In conjunction with the March 1999approval by the IUB of the MidAmerican Energy acquisition and March2000 affirmation as part of the Company's acquisition by aprivate investor group, MidAmerican Energy committed to the IUB to usecommercially reasonable efforts to maintain an investment grade ratingon its long-term debt and to maintain its common equity level above42% of total capitalization unless circumstances beyond itscontrol result in the common equity level decreasing to below39% of total capitalization. MidAmerican Energy must seek theapproval of the IUB of a reasonable utility capital structure ifMidAmerican Energy's common equity level decreases below42% of total capitalization, unless the decrease is beyond thecontrol of MidAmerican Energy. MidAmerican Energy is also 

21

----

required to seek the approval of the IUB ifMidAmerican Energy's equity level decreases to below 39%,even if the decrease is due to circumstances beyond the control ofMidAmerican Energy. If MidAmerican Energy's common equity levelwere to drop below the required thresholds, MidAmerican Energy'sability to issue debt could be restricted.

With the eliminationof its energy adjustment clause in Iowa in 1997, MidAmerican Energy isfinancially exposed to movements in energy prices. Although MidAmericanEnergy has sufficient low cost generation under typical operatingconditions for its retail electric needs, a loss of adequate generationby MidAmerican Energy requiring the purchase of replacement power at atime of high market prices could subject MidAmerican Energy to losseson its energy sales.

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

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

If implemented, theFERC's July 2002 proposed rule for SMD would require sweepingchanges to the use and expansion of the interstate transmission andwholesale bulk power systems in the United States. However, it isunclear when or even whether FERC will issue a final rule and what formthe final rule would ultimately take. In response to significantcriticism of its proposed rule, the FERC subsequently indicated that ithad changed its proposal and would adopt a flexible approach to SMDthat would accommodate regional differences. Legislation that iscurrently pending in Congress would forbid the FERC from implementingthe SMD rule for several years, but it is not certain whether thatlegislation will be adopted. Any final rule on SMD may impact the costsof MidAmerican Energy's electricity and transmission products. Afinal rule on SMD could directly or indirectly influence howtransmission services are priced, the availability of transmissionservices, and how transmission services are obtained. In addition, therule could affect how wholesale electricity is bought and sold, as wellas the geographic scope of the wholesale marketplace in whichMidAmerican Energy buys and sells electricity. MidAmerican Energyrecognizes there is considerable uncertainty as to the timing andoutcome of this rulemaking and will continue to evaluate the status ofthe adoption of SMD for the wholesale markets. Transferring theoperations and control of MidAmerican Energy's transmissionassets to other entities could increase costs for MidAmerican Energy;however, the actual effect of any such transaction on MidAmericanEnergy's future transmission costs, or alternate RTO strategies,is not yet known.

Under two settlement agreements approved bythe IUB, MidAmerican Energy's Iowa retail electric rates ineffect on December 31, 2000, are effectively frozen through December31, 2010. The settlement agreements specifically allow the filing ofelectric rate design or cost of service rate changes that are intendedto keep MidAmerican Energy's overall Iowa retail electric revenueunchanged, but could result in changes to individual tariffs. Thesettlement agreements also each provide that portions of revenuesassociated with Iowa retail electric returns on equity within specifiedranges will be recorded as a regulatory liability to be used to offseta portion of the cost to Iowa customers of future generating plantinvestment.

Under the first settlement agreement, which wasapproved by the IUB on December 21, 2001, and is effective throughDecember 31, 2005, an amount equal to 50% of revenues associatedwith returns on equity between 12% and 14%, and83.33% of revenues associated with returns on equity above14%, in each year is recorded as a regulatory liability. Thesecond settlement agreement, which was filed in conjunction withMidAmerican Energy's application for ratemaking principles on awind power project 

22

----

and was approved by the IUB on October 17,2003, provides that during the period January 1, 2006 through December31, 2010, an amount equal to 40% of revenues associated withreturns on equity between 11.75% and 13%, 50% ofrevenues associated with returns on equity between 13% and14%, and 83.3% of revenues associated with returns onequity above 14%, in each year will be recorded as a regulatoryliability. An amount equal to the regulatory liability is recorded as aregulatory charge in depreciation and amortization expense when theliability is accrued. Future depreciation will be reduced as a resultof the credit applied to generating plant balances as the regulatoryliability is reduced. The liability is being reduced as it is creditedagainst plant in service in amounts equal to the allowance for fundsused during construction associated with generating plant additions.Interest expense is accrued on the portion of the regulatory liabilityrelated to prior years.

The 2003 settlement agreement alsoprovides that if Iowa retail electric returns on equity fall below10% 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, MidAmericanEnergy is required by the settlement agreement to conduct 30 days ofgood faith negotiations with all of the signatories to the settlementagreement to attempt to avoid a general increase in rates.

Illinois bundled electric rates are frozen until 2007, subject tocertain exceptions allowing for increases, at which time bundled ratesare subject to cost-based ratemaking. Illinois law provides forIllinois earnings above a computed level of return on common equity tobe shared equally between regulated retail electric customers andMidAmerican Energy. MidAmerican Energy's computed level of returnon common equity is based on a rolling two-year average of the MonthlyTreasury Long-Term Average Rate, as published by the Federal ReserveSystem, plus a premium of 8.5% for 2000 through 2004 and apremium of 12.5% for 2005 and 2006. The two-year average abovewhich sharing must occur for 2003 was 13.73%. The law allowsMidAmerican Energy to mitigate the sharing of earnings above thethreshold return on common equity through accelerated recovery ofelectric assets.

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

KernRiver and Northern Natural Gas

Kern River and NorthernNatural Gas are subject to regulation by various federal and stateagencies. As owners of interstate natural gas pipelines, NorthernNatural Gas' and Kern River's rates, services andoperations are subject to regulation by the FERC. The FERC administers,among other things, the Natural Gas Act and the Natural Gas Policy Actof 1978. Additionally, interstate pipeline companies are subject toregulation by the Department of Transportation pursuant to the NaturalGas Pipeline Safety Act, which establishes safety requirements in thedesign, construction, operations and maintenance of interstate naturalgas transmission facilities.

The FERC has jurisdiction over,among other things, the construction and operation of pipelines andrelated facilities used in the transportation, storage and sale ofnatural gas in interstate commerce, including the modification orabandonment of such facilities. The FERC also has jurisdiction over therates and charges and terms and conditions of service for thetransportation of natural gas in interstate commerce. Its pipelinesubsidiaries also are required to file with the FERC an annual reporton Form 2, which is publicly available, disclosing general corporateinformation and financial statements regarding its pipelinesubsidiaries.

Kern River's tariff rates were designed togive it an opportunity to recover all actually and prudently incurredoperations 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 "levelizedcost-of-service" methodology so that the rate is constantover the contract period. This is achieved by using a FERC-approveddepreciation schedule in which depreciation increases as interestexpense decreases.

23

----

Northern Natural Gas has implemented astraight fixed variable rate design which provides that all fixed costsassignable to firm capacity customers, including a return on equity,are to be recovered through fixed monthly demand or capacityreservation charges which are not a function of throughput volumes.

On May 1, 2003, Northern Natural Gas filed a request for increasedrates with the FERC. The rate filing provides evidence in support of a$71 million increase to Northern Natural Gas' annual revenuerequirement. However, Northern Natural Gas is requesting that only $55million 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 theFERC to increase its revenue requirement by an incremental $30million to that requested in the May 1, 2003 filing. Northern NaturalGas requested that the new rates be effective commencing August 1,2004. Northern Natural Gas has filed to consolidate the two rateproceedings, but the FERC has not yet ruled on Northern NaturalGas' motion.

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

Other United States Regulation

PURPA and the PublicUtility Holding Company Act of 1935, as amended("PUHCA"), are two of the laws (including theregulations thereunder) that affect MEHC and certain of itssubsidiaries' operations. PURPA provides to QFs certainexemptions from federal and state laws and regulations, includingorganizational, rate and financial regulation. PUHCA extensivelyregulates and restricts the activities of registered public utilityholding companies and their subsidiaries. Congress is currentlyconsidering major changes to both PUHCA and PURPA. Any suchlegislation, if adopted, could vary considerably from the terms whichare presently under consideration. MEHC believes that if the currentproposed legislation is passed, it would apply to new projects only andthus, although potentially impacting its ability to develop newdomestic projects, it would not affect MEHC's existing qualifyingfacilities. MEHC cannot provide assurance, however, that legislation,if passed, or any other similar legislation proposed in the future,would not adversely impact its existing domestic projects.

TheCompany is currently exempt from regulation under all provisions ofPUHCA, except the provisions that regulate the acquisition ofsecurities of public utility companies, based on the intrastateexemption in Section 3(a)(1) of PUHCA. In order to maintain thisexemption, MEHC and each of its public utility subsidiaries from whichit derives a material part of its income (currently only MidAmericanEnergy) must be predominantly intrastate in character and organized inand carry on MEHC's and MidAmerican Energy's respectiveutility operations substantially in MidAmerican Energy's state oforganization (currently Iowa). Except for MidAmerican Energy'sgenerating plant assets, the majority of MEHC's domestic powerplant operations and all of its foreign utility operations are notpublic utilities within the meaning of PUHCA as a result of theirstatus as QFs under PURPA (with MEHC's ownership interest thereinlimited to 50%), EWGs or foreign utility companies, or areotherwise exempted from the definition of "publicutility" under PUHCA. Although MEHC believes that it willcontinue to qualify for exemption from additional regulation underPUHCA, it is possible that as a result of the expansion of its publicutility operations, loss of exempt status by one or more of itsdomestic power plants or foreign utilities, or amendments to PUHCA orthe interpretation of PUHCA, MEHC could become subject to additionalregulation under PUHCA in the future. There can be no assurances thatsuch regulation would not have a material adverse effect on theCompany.

In the event the Company was unable to avoid the lossof QF status for one or more of its affiliate's facilities, suchan event could result in termination of a given project's powersales agreement and a default under the project subsidiary'sproject financing agreements, which, in the event of the loss of QFstatus for one or more facilities, could have a material adverse effecton the Company.

Regulatory requirements applicable in the futureto nuclear generating facilities could adversely affect the results ofoperations of MEHC and MidAmerican Energy, in particular. The Companyis subject to certain generic risks associated with utility nucleargeneration, including risks arising from the 

24

----

operation of nuclear facilities and thestorage, handling and disposal of high-level and low-level radioactivematerials; risks of a serious nuclear incident; limitations on theamounts and types of insurance commercially available in respect oflosses that might arise in connection with nuclear operations; anduncertainties with respect to the technological and financial aspectsof decommissioning nuclear plants at the end of their licensed lives.The Nuclear Regulatory Commission ("NRC") hasbroad authority under federal law to impose licensing andsafety-related requirements for the operation of nuclear generatingfacilities. Revised safety requirements promulgated by the NRC have, inthe past, necessitated substantial capital expenditures at nuclearplants, including those in which MidAmerican Energy has an ownershipinterest, such as the Quad Cities units, and additional suchexpenditures could be required in the future.

PipelineSafety Regulation

The Company's pipeline operationsare subject to regulation by the United States Department ofTransportation ("DOT") under the Natural GasPipeline Safety Act of 1968 ("NGPSA")relating to design, installation, testing, construction, operation andmanagement of its pipeline system. The NGPSA requires any entity thatowns or operates pipeline facilities to comply with applicable safetystandards, to establish and maintain inspection and maintenance plansand to comply with such plans. The Company's pipeline operationsconduct internal audits of their facilities every four years, with morefrequent reviews of those it deemed of higher risk. The DOT alsoroutinely audits these pipeline facilities. Compliance issues thatarise during these audits or during the normal course of business areaddressed on a timely basis.

The aging pipeline infrastructurein the United States has led to heightened regulatory and legislativescrutiny of pipeline safety and integrity practices. The NGPSA wasamended by the Pipeline Safety Act of 1992 to require the DOT'sOffice of Pipeline Safety to consider protection of the environmentwhen developing minimum pipeline safety regulations. In addition, theamendments require that the DOT issue pipeline regulations concerning,among other things, the circumstances under which emergency flowrestriction devices should be required, training and qualificationstandards for personnel involved in maintenance and operation, andrequirements for periodic integrity inspections, as well as periodicinspection of facilities in navigable waters which could pose a hazardto navigation or public safety. In addition, the amendments narrowedthe scope of its gas pipeline exemption pertaining to undergroundstorage tanks under the Resource Conservation and Recovery Act. TheCompany believes its pipeline operations comply in all materialrespects with the NGPSA.

The Pipeline Safety Improvement Actrequires major new programs in the areas of operator qualification,risk analysis and integrity management. The Act requires the periodicinspection or testing of pipelines in areas where the potentialconsequences of a gas pipeline accident may be significant or may doconsiderable harm to people and their property, which are referred toas High Consequence Areas. Pursuant to this Act, the DOT promulgated amajor new final rule, effective February 14, 2004, that requiresinterstate pipeline operators to: develop comprehensive integritymanagement programs, identify applicable threats to pipeline segmentsthat could impact High Consequence Areas, assess these segments, andprovide ongoing mitigation and monitoring.

CE ElectricUK

Since 1990, the electricity generation, supply anddistribution industries in Great Britain have been privatized, andcompetition has been introduced in generation and supply. Electricityis produced by generators, transmitted through the national gridtransmission system and distributed to customers by the fourteenDistribution License Holders ("DLHs") intheir respective distribution service areas.

Under the UtilitiesAct 2000, the public electricity supply license created pursuant to theElectricity Act 1989 was replaced by two separate licenses-theelectricity distribution license and the electricity supply license.When the relevant provision of the Utilities Act 2000 became effectiveon October 1, 2001, the public electricity supply licenses formerlyheld by Northern Electric and Yorkshire were split so that separatesubsidiaries held licenses for electricity distribution and electricitysupply. In order to comply with the Utilities Act 2000 and tofacilitate this license splitting, Northern Electric and Yorkshire (andeach of the other holders of the former public electricity supplylicenses) each made a statutory transfer 

25

----

scheme that was approved by the Secretary ofState for Trade and Industry. These schemes provided for the transferof certain assets and liabilities to the licensed subsidiaries. Thisoccurred on October 1, 2001, a date set by the Secretary of State forTrade and Industry. As a consequence of these schemes, the electricitydistribution businesses of Northern Electric and Yorkshire weretransferred to NED and YED, respectively. NED and YED are each holdersof an electricity distribution license. The residual elements of theelectricity supply licenses were transferred to Innogy in connectionwith the sale of Northern Electric's electricity and gas supplybusiness to Innogy and the retention by Innogy of the electricity andgas supply business of Yorkshire, all as a part of the Yorkshire Swap(an agreement to exchange Northern Electric's electricity and gassupply and metering assets for Innogy's 94.75% interest inYorkshire's electricity distribution business) on September 21,2001.

Each of the DLHs is required to offer terms for connectionto its distribution system and for use of its distribution system toany person. In providing the use of its distribution system, a DLH mustnot discriminate between users, nor may its charges differ except wherejustified by differences in cost.

Most revenue of the DLHs iscontrolled by a distribution price control formula which is set out inthe license of each DLH. It has been the practice of the Office of Gasand Electricity Markets ("Ofgem") (and itspredecessor body, the Office of Electricity Regulation), to review andreset the formula at five year intervals, although the formula may befurther reviewed at other times at the discretion of the regulator. Anysuch resetting of the formula requires the consent of the DLH. If theDLH does not consent to the formula reset, it is reviewed by theU.K.'s competition authority.

The periodic review duringwhich the formula is reset is the process by which Ofgem determines itsview of the future allowed revenue of DLHs. The procedure andmethodology adopted at a price control review is at the reasonablediscretion of Ofgem. At the last such review, concluded in 1999 andeffective April 2000, Ofgem's judgment of the future allowedrevenue of licensees was based upon, among other things:

|              |                                                     |
|--------------|-----------------------------------------------------|
| •  | the actual operating costs of each of thelicensees; |

|              |                                                                                                                                         |
|--------------|-----------------------------------------------------------------------------------------------------------------------------------------|
| •  | the operating costs whicheach of the licensees would incur if it were as efficient as, inOfgem's judgment, the most efficient licensee; |

|              |                                                                                           |
|--------------|-------------------------------------------------------------------------------------------|
| •  | the regulatory value to be ascribed toeach of the licensees' distribution network assets; |

|              |                                                                                            |
|--------------|--------------------------------------------------------------------------------------------|
| •  | the allowance for depreciation of thedistribution network assets of each of the licensees; |

|              |                                                                                                        |
|--------------|--------------------------------------------------------------------------------------------------------|
| •  | the rate of return to be allowed oninvestment in the distribution network assets by all licensees; and |

|              |                                                                                                                                   |
|--------------|-----------------------------------------------------------------------------------------------------------------------------------|
| •  | the financial ratios of each of thelicensees and the license requirement for each licensee to maintain aninvestment grade status. |

As a result of the last review, theallowed revenue of NED's distribution business was reduced by24%, in real terms, and the allowed revenue of YED'sdistribution business was reduced by 23%, in real terms, witheffect from April 1, 2000. The range of reductions for all licensees inGreat Britain was between 4% and 33%.

For theduration of the current regulatory period, the 1999 review alsorequires that regulated distribution revenue per unit be increased ordecreased each year by RPI-Xd, where the factor"RPI" is the United Kingdom retail priceindex reflecting the average of the 12-month inflation rates recordedfor each month in the previous July to December period and"Xd" is an adjustment factor which wasestablished by Ofgem at the 1999 review (and continues to be set) at3%. The formula also takes account of the changes in systemelectrical losses, the number of end users connected and the voltage atwhich end  users receive the units of electricity distributed.This formula determines the maximum average price per unit ofelectricity distributed (in pence per kWh) which a DLH is entitled tocharge the suppliers of electricity, which are the DLH'scustomers. The distribution price control formula permits DLHs toreceive additional revenue due to increased distribution of units and apredetermined increase in end users. Once set, the price controlformula does not, during its duration, seek to constrain the profits ofa DLH from year to year. It is a control on revenue that operatesindependently of most of the DLH's costs. Therefore during theduration of the price control, increases or decreases in costs, if any,directly impact profit.

26

----

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

Under the UtilitiesAct 2000, the Gas and Electricity Markets Authority("GEMA") is able to impose financialpenalties on license holders who contravene (or have in the pastcontravened) any of their license duties or certain of their dutiesunder the Electricity Act 1989 or who are failing (or have in the pastfailed) to achieve a satisfactory performance in relation to theindividual standards of performance prescribed by GEMA. Any penaltyimposed must be reasonable and may not exceed 10% of thelicensee's revenue.

CalEnergy Generation –Domestic

Each of the domestic power facilities in theCalEnergy Generation – Domestic platform, excluding CordovaEnergy and Power Resources, meets the requirements promulgated underPURPA to be a QF. QF status under PURPA provides two primary benefits.First, regulations under PURPA exempt QFs from PUHCA, the FERC rateregulation under the Federal Power Act and the state laws concerningrates of electric utilities and financial and organization regulationsof electric utilities. Second, the FERC's regulations promulgatedunder PURPA require that (1) electric utilities purchase electricitygenerated by QFs, the construction of which commenced on or afterNovember 9, 1978, at a price based on the purchasing utility'sAvoided Cost of Energy, (2) electric utilities sell back-up,interruptible, maintenance and supplemental power to QFs on anon-discriminatory basis, and (3) electric utilities interconnect withQFs in their service territories. There can be no assurance that the QFstatus of such CalEnergy Generation – Domestic facilitieswill be maintained.

Cordova Energy and Power Resources areexempt from regulation under PUHCA because they are EWGs. PUHCAprovides that an EWG is not considered to be an electric utilitycompany. An EWG is permitted to sell capacity and electricity in thewholesale markets, but not in the retail markets.

If an EWG issubject to a "material change" in facts thatmight affect its continued eligibility for EWG status, within 60 daysof such material change, the EWG must (1) file a written explanation ofwhy the material change does not affect its EWG status, (2) file a newapplication for EWG status, or (3) notify the FERC that it no longerwishes to maintain EWG status.

CalEnergy Generation– Foreign

The Philippine Congress has passedthe Electric Power Industry Reform Act of 2001("EPIRA"), which is aimed at restructuringthe Philippine power industry, privatizing the NPC and introducing acompetitive electricity market, among other initiatives. Theimplementation of EPIRA may have an impact on MEHC's futureoperations in the Philippines and the Philippines power industry as awhole, the effect of which is not yet determinable or estimable.

In connection with an interagency review of approximately 40independent power project contracts in the Philippines pursuant toEPIRA, in 2003 the Casecnan project (together with four other unrelatedprojects) had reportedly been identified as raising legal and financialquestions and, with those projects, had been prioritized forrenegotiation. In connection with the settlement of the NIA Arbitrationand as part of the Supplemental Agreement, CE Casecnan received writtenconfirmation from the Private Sector Assets and Liabilities ManagementCorporation that the issues with respect to the Casecnan project thathad been raised by the interagency review of independent powerproducers in the Philippines or that may have existed with respect tothe project under certain provisions of EPIRA, which authorized the ROPto seek to renegotiate certain contracts such as the Project Agreement,have been satisfactorily addressed by the Supplemental Agreement. TheCompany's indirect subsidiaries' Leyte Projects also hadreportedly been identified as raising financial questions. Inconnection with the entering into of amendments to the energyconversion agreement for each of the Leyte Projects with PNOC-EDC, MEHCbelieves that any issues raised by the interagency review ofindependent power producers in the Philippines with respect to theLeyte Projects have been resolved.

27

----

CE Casecnan representatives, togetherwith certain current and former government officials, also wererequested to and did appear, during 2002 and the first half of 2003,before a Philippine Senate committee which had raised questions andmade allegations with respect to the Casecnan project's tariffstructure and implementation. The Company believes that as a result ofthe settlement of the NIA Arbitration and the entering into of theSupplemental Agreement the questions and allegations raised by thePhilippine Senate committee have been addressed, although there can beno assurance that additional inquiries by the Philippine Congress orany agency of the Philippine government will not be made in thefuture.

HomeServices

HomeServices is subject toregulations promulgated by the U.S. Department of Housing and UrbanDevelopment ("HUD") as well as regulatoryagencies in the states within which it operates that significantlyinfluence its operating environment. On July 29, 2002, HUD issued aproposed regulation under the Real Estate Settlement and ProceduresAct. HUD has characterized the proposal as "fundamentallychanging the way in which payments to mortgage brokers are recorded andreported to consumers,""significantly" improving the disclosure ofsettlement costs on the Good Faith Estimate making it firmer and moreusable, and "removing regulatory barriers to allowguaranteed packages of settlement services and mortgages to be madeavailable to consumers." The final rule, if adopted ascurrently proposed, would require HomeServices to substantially changethe manner in which mortgage, title insurance and escrow closingservices are marketed and delivered to consumers. Title insurance andescrow closing services, in particular, may be marketed to lenders forinclusion within a lender's guaranteed package of settlementservices. The proposed rule may impact the costs and pricing ofHomeServices' mortgage, title and escrow services. The proposalwas submitted to the Office of Management and Budget("OMB") on December 16, 2003, and it isunknown whether the OMB will release the proposed rule; however, it islikely that the final rule could vary considerably from the initialproposal. Accordingly, the Company is presently unable to quantify thelikely impact of the proposed rule, if adopted.

EnvironmentalRegulation

Domestic

The Company'sdomestic operations are subject to a number of federal, state and localenvironmental and environmentally related laws and regulationsaffecting many aspects of its present and future operations in theUnited States. Such laws and regulations generally require theCompany's domestic operations to obtain and comply with a widevariety of licenses, permits and other approvals. The Company believesthat its operating power facilities and gas pipeline operations arecurrently in material compliance with all applicable federal, state andlocal laws and regulations. However, no guarantee can be given that inthe future the Company's domestic operations will be 100%compliant with all applicable environmental statutes and regulations orthat all necessary permits will be obtained or approved. In addition,the construction of new power facilities and gas pipeline operations isa costly and time-consuming process requiring a multitude of complexenvironmental permits and approvals prior to the start of constructionthat may create the risk of expensive delays or material impairment ofproject value if projects cannot function as planned due to changingregulatory requirements or local opposition. The Company cannot provideassurance that existing regulations will not be revised or that newregulations will not be adopted or become applicable to it which couldhave an adverse impact on its capital or operating costs or itsoperations.

Clean Air Standards

MidAmerican Energy's generating facilities are subject toapplicable provisions of the Clean Air Act and related air qualitystandards promulgated by the United States Environmental ProtectionAgency ("EPA"). The Clean Air Act providesthe framework for regulation of certain air emissions and permittingand monitoring associated with those emissions. MidAmerican Energybelieves it is in material compliance with current air qualityrequirements.

28

----

The EPA has in recent years implementedmore stringent standards for ozone and fine particulate matter.Designations regarding attainment of the eight-hour ozone standard haverecently been reviewed by the EPA, and the EPA has concluded that theentire state of Iowa is in attainment of the standards. On December 4,2003, the EPA announced the development of its Interstate Air QualityRule, a proposal to require coal-burning power plants in 29 states andthe District of Columbia to reduce emissions of sulfur dioxide("SO2") and nitrogen oxides in aneffort to reduce ozone and fine particulate matter in the EasternUnited States. It is likely that MidAmerican Energy'scoal-burning facilities will be impacted by this proposal.

InDecember 2000, the EPA concluded that mercury emissions from coal-firedgenerating stations should be regulated. The EPA is currentlyconsidering two regulatory alternatives for the regulation of mercuryfrom coal-fired utilities as necessary to protect public health. One ofthese alternatives would require reductions of mercury from allcoal-fired facilities greater than 25 MW through application of MaximumAchievable Control Technology with compliance assessed on a facilitybasis. The other alternative would regulate the mercury emissions ofcoal-fired facilities that pose a health hazard through a market basedcap-and-trade mechanism similar to the SO2 allowance system.The EPA is currently under a deadline to finalize the mercury rule byDecember 2004. Any of these new or stricter standards could, in wholeor in part, be superceded or made more stringent by one of a number ofmulti-pollutant emission reduction proposals currently underconsideration at the federal level, including the "ClearSkies Initiative", and other pending legislative proposalsthat contemplate 70% to 90% reductions of SO2,NOX and mercury, as well as possible new federal regulationof carbon dioxide and other gasses that may affect global climatechange.

Depending on the outcome of the final regulations,MidAmerican Energy may be required to install control equipment on itsgenerating stations or decrease the number of hours during which itsgenerating stations operate. However, until final regulations areissued, the impact of the regulations on MidAmerican Energy cannot bepredicted.

While legislative action is necessary for the ClearSkies Initiative or other multi-pollutant emission reductionlegislation to become effective, MidAmerican Energy has implemented aplanning process that forecasts the site-specific controls and actionsrequired to meet emissions reductions of this nature. On April 1, 2002,in accordance with an Iowa law passed in 2001, MidAmerican Energy filedwith the IUB its first multi-year plan and budget for managingSO2 and NOX from its generating facilities in acost-effective manner. The plan provides specific actions to be takenat each coal-fired generating facility and the related costs and timingfor each action. Mercury emissions reductions were not addressed in theplan. On July 17, 2003, the IUB issued an order that affirmed anadministrative law judge's approval of the plan, as amended.Accordingly, the IUB order provides that the approved expenditures willnot be subject to a subsequent prudence review in a future electricrate case, but it rejected the future application of a trackermechanism to recover emission reduction costs. However, pursuant to anunrelated rate settlement agreement approved by the IUB on October 17,2003, if prior to January 1, 2011, capital and operating expendituresto comply with environmental requirements cumulatively exceed$325  million, then MidAmerican Energy may seek to recover theadditional expenditures from customers. At this time, MidAmericanEnergy does not expect these capital expenditures to exceed suchamount.

Under the New Source Review("NSR") provisions of the Clean Air Act, autility is required to obtain a permit from the EPA or a stateregulatory agency prior to (1) beginning construction of a new majorstationary source of an NSR-regulated pollutant or (2) making aphysical or operational change (a "majormodification") to an existing facility that potentiallyincreases emissions, unless the changes are exempt under theregulations. In general, projects subject to NSR regulations aresubject to pre-construction review and permitting under the Preventionof Significant Deterioration ("PSD")provisions of the Clean Air Act. Under the PSD program, a project thatemits threshold levels of regulated pollutants must undergo a BestAvailable Control Technology analysis and evaluate the most effectiveemissions controls. These controls must be installed in order toreceive a permit. Violations of NSR regulations, which may be allegedby the EPA, states and environmental groups, among others, potentiallysubject a utility to material expenses for fines or other sanctions andremedies including requiring installation of enhanced pollutioncontrols and funding supplemental environmental projects.

29

----

In recent years, the EPA has requestedfrom several utilities information and support regarding their capitalprojects for various generating plants. The requests were issued aspart of an industry-wide investigation to assess compliance with theNSR and the New Source Performance Standards of the Clean Air Act. InDecember 2002 and April 2003, MidAmerican Energy received requests fromthe EPA to provide documentation related to its capital projects fromJanuary 1, 1980, to the present for a number of its generating plants.MidAmerican Energy has submitted information to the EPA in responses tothese requests, and there are currently no outstanding data requestspending from the EPA. MidAmerican Energy cannot predict the outcome ofthese requests at this time. However, on August 27, 2003, the EPAannounced changes to its NSR rules that clarify what constitutesroutine repair, maintenance and replacement for purposes of triggeringNSR requirements. The EPA concluded equipment that is repaired,maintained or replaced with an expenditure not greater than 20 percentof the value of the source will not trigger the NSR provisions of theClean Air Act. After the NSR changes were announced, the EPA'senforcement branch indicated it would apply the clarified routinerepair, maintenance and replacement rules to its pending investigation.A number of states and local air districts have challenged theEPA's clarification of the rule and a panel of the U.S. CircuitCourt of Appeals for the District of Columbia issued an order onDecember 24, 2003 staying the EPA's implementation of itsclarification of the equipment replacement rule.

On August 29,2003, the EPA finalized requirements to reduce toxic air emissions fromstationary combustion turbines. These requirements apply to turbinesused at pipeline compressor stations that are built afterJanuary  12, 2003. Kern River and Northern Natural Gas believethe existing turbines are exempt from the rule since the turbines werebuilt and installed at compressor stations built prior to January 12,2003. New turbine installations will likely require the installation ofequipment to reduce formaldehyde emissions and other pollutants to meetthe new requirements and could significantly increase the cost of newturbine installations.

On December 19, 2002, the EPA issuedproposed emission standards for hazardous air pollutants for stationaryreciprocating internal combustion engines, such as those used atpipeline compressor stations. The proposed standards would apply to allnew and certain existing reciprocating internal combustion enginesabove 500 horsepower that are located at facilities characterized underthe Clean Air Act as a "major source" oftoxic air pollutants. While the emission standards have not yet beenfinalized, the impact of any new regulation of hazardous air pollutantsfrom stationary reciprocating internal combustion engines could have asignificant impact on existing and new facilities.

Manufactured Gas Plants

The EPA and thestate environmental agencies have determined that contaminated wastesremaining at decommissioned manufactured gas plant facilities may posea threat to the public health or the environment if such contaminantsare in sufficient quantities and at such concentrations as to warrantremedial action.

MidAmerican Energy has evaluated or isevaluating 27 properties that were, at one time, sites of gasmanufacturing plants in which it may be a potentially responsibleparty. The purpose of these evaluations is to determine whether wastematerials are present, whether the materials constitute a health orenvironmental risk, and whether MidAmerican Energy has anyresponsibility for remedial action. MidAmerican Energy is activelyworking with the regulatory agencies and has received regulatoryclosure on four sites. MidAmerican Energy is continuing to evaluateseveral of the sites to determine the future liability, if any, forconducting site investigations or other site activity.

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

Theestimated liability is determined through a site-specific costevaluation process. The estimate includes incremental direct costs ofremediation, site monitoring costs and costs of compensation toemployees for time expected to be spent directly on the remediationeffort. The estimated recorded 

30

----

liabilities for these properties are basedupon preliminary data. Thus, actual costs could vary significantly fromthe estimates. The estimate could change materially based on facts andcircumstances derived from site investigations, changes in requiredremedial action and changes in technology relating to remedialalternatives. Insurance recoveries have been received for some of thesites under investigation. Those recoveries are intended to be usedprincipally for accelerated remediation, as specified by the IUB andare recorded as a regulatory liability.

Although the timing ofpotential incurred costs and recovery of such costs in rates may affectthe results of operations in individual periods, management believesthat the outcome of these issues will not have a material adverseeffect on MidAmerican Energy's financial position, results ofoperations or cash flows.

United Kingdom

CEElectric UK's businesses are subject to extensive regulatoryrequirements with respect to the protection of the environment.

The United Kingdom government introduced new contaminated landlegislation in April 2000 that requires local governmental authoritiesto put in place a program for investigating land in their area in orderto identify contamination. Local authorities (and the EnvironmentAgency where controlled waters are affected) can enforce remedialaction where such contamination of land poses a threat to the greaterenvironment. If the "person" who contaminatedthe land cannot be found, the land owner will be held responsible.

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

The EnvironmentalProtection Act (Disposal of PCB's and other Dangerous Substances)Regulations 2001 were introduced on May 5, 2000. The regulationsrequired that transformers containing over 50 parts per million ofPCB's and other dangerous substances be registered with theEnvironment Agency. Transformers containing 500 parts per million hadto be de-contaminated by December 31, 2000. As of December 31, 2003, CEElectric UK had 318 transformers containing between 50 and 500 partsper million of such substances registered with the Environment Agencyand is continuing with its sampling, labeling and registration program.CE Electric UK believes it is in compliance and these regulations arenot expected to have a material impact on the Company.

The 1998Groundwater Regulations seek to prevent listed hazardous substancesfrom entering groundwater and strengthens the United KingdomEnvironment Agency's powers to require additional protectivemeasures, especially in areas of important groundwater supplies.Mineral oils and hydrocarbons are included in the list of more tightlycontrolled substances ("List I substances").This affects the high voltage fluid filled electricity cable networkincorporating an insulating fluid that is currently in List  I.The existing voluntary Operating Code of Practice, as agreed betweenthe Environment Agency and companies in the electricity industry, isundergoing revision to address the regulatory changes. The existingvoluntary Operating Code of Practice is, and any revised Operating Codeof Practice will be, incorporated into the operating practices of NEDand YED. Any revisions which are made are not expected to have amaterial impact on the Company.

The Oil Storage Regulationsbecame effective in 2002 and require the phased introduction ofsecondary containment measures (bunding) for all above ground oilstorage locations where the capacity is more than 200 liters. Theprimary containers must be in sound condition, leak free, andpositioned away from vehicle traffic routes. The secondary containmentmust be impermeable to water and oil (without drainage valve) and besubject to routine maintenance. The capacity of the bund must besufficient to hold up to 110% of the largest stored vessel or25% of the maximum stored capacity, whichever is the greater. OnMarch 1, 2002, these regulations came into effect for all new oilstorage facilities. On September 1, 2003, the regulations becameeffective for existing storage facilities at "significantrisk" (i.e. within 10 meters of a water course), and onSeptember 1, 2005, the regulations come into effect for all remaining

31

----

storage facilities. A detailed study of theimpacts has been carried out and a plan of action prepared to ensurecompliance. The Company expects that the cost of compliance with suchregulations will not have a material impact.

The Electricity Act1989 obligates either the United Kingdom Secretary of State or theDirector General of Electric Supply to take into account the effect ofelectricity generation, transmission and supply activities on thephysical environment when approving applications for the constructionof overhead power lines. The Electricity Act requires CE Electric UK toconsider the desirability of preserving natural beauty and theconservation of natural and man-made features of particular interestwhen it formulates proposals for development in connection with certainof its activities. CE Electric UK mitigates the effects its proposalshave on natural and man-made features and administers an environmentalassessment when it intends to lay cables, construct overhead lines orcarry out any other development in connection with its licensedactivities. The Company expects that the cost of compliance with theseobligations and the mitigation thereof will not have a materialimpact.

CE Electric UK's policy is to carry out itsactivities in such a manner as to minimize the impact of its works andoperations on the environment, and in accordance with environmentallegislation and good practice. There have not been any significantregulatory environmental compliance issues and there are no materiallegal or administrative proceedings pending against CE Electric UK withrespect to any environmental matter.

Environmental laws andregulations in the United Kingdom currently have, and futuremodifications may increasingly have, the effect of requiringmodification of CE Electric UK's facilities and increasing itsoperating costs.

Philippines

On June 23, 1999,the Philippine Congress enacted the Philippine Clean Air Act of 1999.The related implementing rules and regulations were adopted in November2000. The law as written would require the Leyte Projects to complywith a maximum discharge of 200 grams of hydrogen sulfide per gross MWhof output by June 2004. On November 13, 2002, the Secretary of thePhilippine Department of Environment and Natural Resources issued aMemorandum Circular ("MC") designatinggeothermal areas as "special airsheds."PNOC-EDC has advised MEHC that the MC exempts the Mahanagdong andMalitbog plants from the need to comply with the point-source emissionstandards of the Clean Air Act. CE Cebu and PNOC-EDC have constructed agas dispersion facility for the Upper Mahiao project which is designedto ensure compliance with the emission standards of the Clean Air Act.The gas dispersion project was put into commercial operation inDecember 2003.

Nuclear Regulation

MidAmericanEnergy is subject to the jurisdiction of the NRC with respect to itslicense and 25% ownership interest in Quad Cities Station Units1 and 2. Exelon Generation is the operator of Quad Cities Station andis under contract with MidAmerican Energy to secure and keep in effectall necessary NRC licenses and authorizations.

The NRCregulations control the granting of permits and licenses for theconstruction and operation of nuclear generating stations and subjectsuch stations to continuing review and regulation. The NRC review andregulatory process covers, among other things, operations, maintenance,and environmental and radiological aspects of such stations. The NRCmay modify, suspend or revoke licenses and impose civil penalties forfailure to comply with the Atomic Energy Act, the regulations undersuch Act or the terms of such licenses. Quad Cities Station licensescurrently expire in 2012. Exelon Generation submitted an application torenew 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 through2032.

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

32

----

with the Department of Energy to provide forthe disposal of spent nuclear fuel and high-level radioactive wastebeginning not later than January 1998. The Department of Energy did notbegin receiving spent nuclear fuel on the scheduled date, and theschedule will be significantly delayed. The earliest expectation forcompletion is now 2010. The costs to be incurred by the Department ofEnergy for disposal activities are being financed by fees charged toowners and generators of the waste. Exelon Generation has informedMidAmerican Energy that existing on-site storage capability at QuadCities Station is sufficient to permit interim storage into 2005. ForQuad Cities Station, Exelon Generation has begun to develop an interimspent fuel storage installation ("ISFSI") atQuad Cities Station to store spent nuclear fuel in dry casks in orderto free space in the storage pool. The first pad at the ISFSI isexpected to facilitate storage of casks to support operations at QuadCities Station until at least 2017. Exelon Generation expects the bulkof the construction work will be done in 2004 with the first caskloading to take place in 2005. In the 2017 to 2022 timeframe, ExelonGeneration plans to add a second pad to the ISFSI to accommodatestorage of spent nuclear fuel through the end of operations at QuadCities Station.

Federal regulations provide that any nuclearoperating facility may be required to cease operation if the NRCdetermines there are deficiencies in state, local or utility emergencypreparedness plans relating to such facility, and the deficiencies arenot corrected. Exelon Generation has advised MidAmerican Energy that anemergency preparedness plan for Quad Cities Station has been approvedby the NRC. Exelon Generation has also advised MidAmerican Energy thatstate and local plans relating to Quad Cities Station have beenapproved by the Federal Emergency Management Agency.

The NRCalso regulates the decommissioning of nuclear power plants includingthe planning and funding for the eventual decommissioning of theplants. In accordance with these regulations, MidAmerican Energysubmits a report to the NRC every two years providing reasonableassurance that funds will be available to pay the costs ofdecommissioning its share of Quad Cities Station.

MidAmericanEnergy has established external trusts for the investment of fundscollected for nuclear decommissioning associated with Quad CitiesStation. Electric tariffs currently in effect include provisions forannualized collection of estimated decommissioning costs at Quad CitiesStation. In Iowa, estimated Quad Cities Station decommissioning costsare reflected in base rates. MidAmerican Energy's cost related todecommissioning funding in 2003 was $8.3 million.

Employees

As of December 31, 2003, the Company employedapproximately 11,440 people, of which approximately 3,820 arerepresented by labor unions.

Item 2.    Properties.

The Company's utility properties consist of physical assetsnecessary and appropriate to render electric and gas service in itsservice territories. Electric property consists primarily ofgeneration, transmission and distribution facilities. Gas propertyconsists primarily of distribution plants, natural gas pipelines,related rights-of-way, compressor stations and meter stations. It isthe opinion of management that the principal depreciable propertiesowned by the Company are in good operating condition and wellmaintained. Pursuant to separate financing agreements, substantiallyall or most of the properties of each subsidiary (except CE Electric UKand Northern Natural Gas) are pledged or encumbered to support orotherwise provide the security for their own project or subsidiarydebt. See Note 5 and Note 20 in "Item 8. FinancialStatements and Supplementary Data — Notes to ConsolidatedFinancial Statements" for additional information about theCompany's properties.

MidAmerican Energy

MidAmerican Energy's most significant properties are itselectric generation facilities. It is the opinion of management thatthe principal depreciable properties owned by MidAmerican Energy are ingood operating condition and well maintained. For a discussion of thesegeneration facilities, see "Item  1. Business— MidAmerican Energy." MidAmerican Energy'sutility properties consist of physical assets necessary and appropriateto render electric and gas service in its service territories. Electricproperty consists primarily of generation, transmission anddistribution facilities.

33

----

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

Gasproperty consists primarily of natural gas mains and servicespipelines, meters and related distribution equipment, including feederlines 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 distinguishablesections: the mainline and the common facilities. The mainline sectionis comprised of the original 680 miles of 36-inch pipeline and 634.3miles of 36-inch loop pipeline, and extends from the pipeline'spoint of origination in Opal, Wyoming through the Central RockyMountains area to Daggett, California and is owned entirely by KernRiver. The common facilities consist of the 219-mile section ofpipeline that extends from Daggett to Bakersfield, California. Thecommon facilities are jointly owned by Kern River (currentlyapproximately 76.8%) and Mojave (currently approximately23.2%) as tenants-in-common.

At December 31, 2003,Northern Natural Gas' system was comprised of approximately 7,300miles of mainline transmission pipes and approximately 9,200 miles ofsmaller diameter branch lines and laterals. Northern Natural Gas'storage services are provided through the operation of threeunderground storage fields, in Redfield, Iowa, and Lyons andCunningham, Kansas. Northern Natural Gas' three undergroundnatural gas storage facilities and liquefied natural gas storagepeaking units have a total storage capacity of approximately 59 Bcf.Northern Natural Gas' two LNG liquefaction/vaporizationfacilities are located near Garner, Iowa and Wrenshall, Minnesota withstorage capacity of 2 Bcf each.

The right to construct andoperate the pipelines across certain property was obtained throughnegotiations and through the exercise of the power of eminent domain,where necessary. Kern River and Northern Natural Gas continue to havethe power of eminent domain in each of the states in which they operatetheir respective pipelines, but they do not have the power of eminentdomain with respect to Native American tribal lands. Although the mainKern River pipeline crosses the Moapa Indian Reservation, allfacilities are located within a utility corridor that is reserved tothe United States Department of Interior, Bureau of LandManagement.

With respect to real property, each of the pipelinesfalls into two basic categories: (1) parcels that are owned in fee,such as certain of the compressor stations, measurement stations anddistrict office sites; and (2) parcels where the interest derives fromleases, easements, rights-of-way, permits or licenses from landownersor governmental authorities permitting the use of such land for theconstruction, operation and maintenance of the pipelines.

MEHCbelieves that Kern River and Northern Natural Gas each havesatisfactory title to all of the real property making up theirrespective pipelines in all material respects.

CE ElectricUK

At December 31, 2003, NED's and YED'selectricity distribution networks (excluding service connection toconsumers) on a combined basis included approximately 29,000 kilometersof overhead lines and approximately 63,000 kilometers of undergroundcables. In addition to the circuits referred to above, at December 31,2003, NED's and YED's distribution facilities also includedapproximately 57,000 transformers and approximately 750 primarysubstations.

Other Properties

At December 31, 2003,MEHC's most significant physical properties, other than thoseowned by MidAmerican Energy, CE Electric UK, Kern River and NorthernNatural Gas, are its current interests in operating power facilitiesand its plants under construction and related real property interests,as well as leases of office space for its residential real estatebrokerage operations. See " Item 1. Business"for further detail.

34

----

Item 3.    Legal Proceedings.

In addition to the proceedings described below, the Company iscurrently party to various items of litigation or arbitration, none ofwhich are reasonably expected by the Company to have a material adverseeffect on its financial position, results of operations or cashflows.

Pipeline Litigation

In 1998, the United StatesDepartment of Justice informed the then current owners of Kern Riverand Northern Natural Gas that Jack Grynberg, an individual, had filedclaims in the United States District Court for the District of Coloradounder the False Claims Act against such entities and certain of theirsubsidiaries including Kern River and Northern Natural Gas. Mr.Grynberg has also filed claims against numerous other energy companiesand alleges that the defendants violated the False Claims Act inconnection with the measurement and purchase of hydrocarbons. Therelief sought is an unspecified amount of royalties allegedly not paidto the federal government, treble damages, civil penalties,attorneys' fees and costs. On April 9, 1999, the United StatesDepartment of Justice announced that it declined to intervene in any ofthe Grynberg qui tam cases, including the actions filed against KernRiver and Northern Natural Gas in the United States District Court forthe District of Colorado. On October 21, 1999, the Panel onMulti-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 forpre-trial purposes. Motions to dismiss the complaint, filed by variousdefendants including Northern Natural Gas and The Williams Companies,Inc. ("Williams"), which was the former ownerof Kern River, were denied on May 18, 2001. On October 9, 2002, theUnited States District Court for the District of Wyoming dismissedGrynberg's royalty valuation claims. On November 19, 2002, theUnited States District Court for the District of Wyoming deniedGrynberg's motion for clarification and dismissed his royaltyvaluation claims. Grynberg appealed this dismissal to the United StatesCourt of Appeals for the Tenth Circuit and on May 13, 2003, the TenthCircuit Court dismissed his appeal. In connection with the purchase ofKern River from Williams in March 2002, Williams agreed to indemnifyMEHC against any liability for this claim; however, no assurance can begiven as to the ability of Williams to perform on this indemnity shouldit become necessary. No such indemnification was obtained in connectionwith the purchase of Northern Natural Gas in August 2002. The Companybelieves that the Grynberg cases filed against Kern River and NorthernNatural Gas are without merit and that Williams, on behalf of KernRiver pursuant to its indemnification, and Northern Natural Gas, intendto defend these actions vigorously.

On June 8, 2001, a number ofinterstate pipeline companies, including Kern River and NorthernNatural Gas, were named as defendants in a nationwide class actionlawsuit which had been pending in the 26th Judicial District, DistrictCourt, Stevens County Kansas, Civil Department against otherdefendants, generally pipeline and gathering companies, since May 20,1999. The plaintiffs allege that the defendants have engaged inmismeasurement techniques that distort the heating content of naturalgas, resulting in an alleged underpayment of royalties to the class ofproducer plaintiffs. In November 2001, Kern River and Northern NaturalGas, along with the coordinating defendants, filed a motion to dismissunder Rules 9B and 12B of the Kansas Rules of Civil Procedure. Thecourt denied this motion. In January 2002, Kern River and most of thecoordinating defendants filed a motion to dismiss for lack of personaljurisdiction. The court has yet to rule on these motions. Theplaintiffs filed for certification of the plaintiff class on September16, 2002. On January 13, 2003, oral arguments were heard oncoordinating defendants' opposition to class certification. OnApril 10, 2003, the court entered an order denying theplaintiffs' motion for class certification. On May 12, 2003, theplaintiffs filed a motion for leave to file a fourth amended petitionalleging a class of gas royalty owners in Kansas, Colorado and Wyoming.The court granted the motion for leave to amend on July 28, 2003. KernRiver was not a named defendant in the amended complaint and has beendismissed from the action. Northern Natural Gas filed an answer on thefourth amended petition on August 22, 2003. Williams has agreed toindemnify MEHC against any liability associated with Kern River forthis claim; however, no assurance can be given as to the ability ofWilliams to perform on this indemnity should it become necessary.Northern Natural Gas anticipates joining with the other defendants incontesting certification of the plaintiff class. Kern River andNorthern Natural Gas believe that this claim is without merit and thatKern River's and Northern Natural Gas' gas measurementtechniques have been in accordance with industry standards and itstariff.

35

----

Similar to the June 8, 2001 matterreferenced above, the plaintiffs in that matter have filed a newcompanion action against a number of parties, including NorthernNatural Gas but excluding Kern River, in a Kansas state district courtfor damages for mismeasurement of British thermal unit content,resulting in lower royalties. The action was filed on May 12, 2003,shortly after the state district court dismissed the plaintiffs'third amended petition in the original litigation which sought tocertify a nationwide class. The new companion action which seeks tocertify 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 onAugust 25, 2003. On October 9, 2003, the state district court deniedthe motion to dismiss; Northern Natural Gas filed its answer onNovember 6, 2003. Northern Natural Gas believes that this claim iswithout merit and that Northern Natural Gas' gas measurementtechniques have been in accordance with industry standards and itstariff.

Natural Gas Commodity Litigation

MidAmericanEnergy is one of dozens of companies named as defendants in a January20, 2004 consolidated class action lawsuit filed in the U.S. DistrictCourt for the Southern District of New York. The suit alleges that thedefendants have engaged in unlawful manipulation of the prices ofnatural gas futures and options contracts traded on the New YorkMercantile Exchange ("NYMEX") during theperiod January 1, 2000 to December 31, 2002. MidAmerican Energy ismentioned as a company that has engaged in wash trades on Enron Online(an electronic trading platform) that had the effect of distortingprices for gas trades on the NYMEX. The plaintiffs to the class actiondo not specify the amount of alleged damages. At this time, MidAmericanEnergy does not believe that it has any material exposure in thislawsuit.

The original complaint in this matter, CornerstonePropane Partners, L.P. v. Reliant, et al.("Cornerstone"), was filed on August 18,2003 in the United States District Court, Southern District of New Yorknaming MidAmerican Energy and the Company. On October 1, 2003, a secondcomplaint, Roberto, E. Calle Gracey, et al. ("CalleGracey"), was filed in the same court but did not nameMidAmerican Energy or the Company. On November 14, 2003, a thirdcomplaint, Dominick Viola ("Viola"), etal., was filed in the same court and named MidAmerican Energy andMEHC as defendants. On November 19, 2003, an Order of VoluntaryDismissal Without Prejudice of MEHC was entered by the court dismissingMEHC from the Cornerstone and Viola complaints. OnDecember 5, 2003, the court entered Pretrial Order No. 1, which amongother procedural matters, ordered the consolidation of theCornerstone, Calle Gracey and Viola complaints andpermitted plaintiffs to file an amended complaint in this matter. OnJanuary 20, 2004, plaintiffs filed In Re: Natural Gas CommodityLitigation as the amended complaint reasserting their previousallegations. Unless extended by agreement of the parties or by courtorder, MidAmerican Energy's answer and/or responsive pleading inthis matter is due February 19, 2004. MidAmerican Energy willcoordinate with the other defendants and vigorously defend theallegations against it.

Philippines

CE Casecnan NIAArbitration

The CE Casecnan NIA arbitration was settled onOctober 15, 2003. See "Item 1. Business — CalEnergyGeneration – Foreign" for additionalinformation.

CE Casecnan Construction ContractArbitration

The Casecnan project was constructed pursuantto a fixed-price, date-certain, turnkey construction contract by aconsortium consisting of Cooperativa Muratori Cementisti CMC di Ravennaand Impresa Pizzarotti & C. Spa. (collectively, the"Contractor"), working together with SiemensA.G., Sulzer Hydro Ltd., Black & Veatch and Colenco PowerEngineering Ltd.

In 2001, the Contractor filed a Request forArbitration (and two supplements) with the International Chamber ofCommerce ("ICC") seeking schedule relief ofup to 153 days, compensation for alleged 

36

----

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

On November 7, 2002, the ICC issued thearbitration tribunal's partial award with respect to theContractor's force majeure claims. The arbitration panel awardedthe Contractor 18 days of schedule relief in the aggregate for all ofthe force majeure events and awarded the Contractor $3.8 million to theextent losses are not covered by insurance. All of theContractor's other claims with respect to force majeure andgeologic conditions were denied. If the Contractor were to prevail onthe Contractor's claim that the delay liquidated damages clauseis unenforceable, CE Casecnan would not be entitled to collect suchdelay damages for the period from March 31, 2001 through December 11,2001. If the Contractor were to prevail in the Contractor'srepudiation claim and prove quantum meruit damages in excess of amountspaid to the Contractor, CE Casecnan could be liable to make additionalpayments to the Contractor. CE Casecnan believes all of suchallegations and claims are without merit and is vigorously contestingthe Contractor's claims. CE Casecnan believes that an award willbe issued by the ICC in 2004.

CE Casecnan StockholderLitigation

Pursuant to the share ownership adjustmentmechanism in the CE Casecnan stockholder agreement, which is based uponpro forma financial projections of the Casecnan project preparedfollowing 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"), thatMEHC's ownership interest in CE Casecnan had increased to100% effective from commencement of commercial operations. InApril 2002, CE Casecnan Ltd. and LPG entered into a status quoagreement pursuant to which CE Casecnan Ltd. agreed not to take anyaction to exercise control over or transfer LPG's shares in CECasecnan. On July 8, 2002, LPG filed a complaint in the Superior Courtof the State of California, City and County of San Francisco against,among others, CE Casecnan Ltd. and MEHC. In the complaint, LPG seekscompensatory and punitive damages for alleged breaches of thestockholder agreement and alleged breaches of fiduciary dutiesallegedly owed by CE Casecnan Ltd. and MEHC to LPG. The complaint alsoseeks injunctive relief against all defendants and a declaratoryjudgment that LPG is entitled to maintain a 15% interest in CECasecnan. On January 21, 2004, CE Casecnan Ltd. and LPG entered into asecond status quo agreement pursuant to which the parties agreed to setaside certain distributions related to the shares subject to the LPGdispute and not distribute such funds without at least 15 days priornotice to LPG. Accordingly, 15% of the dividend distributiondeclared on January 21, 2004 was set aside by CE Casecnan in anunsecured CE Casecnan account. The impact, if any, of this litigationon the Company cannot be determined at this time.

Item4.    Submission of Matters to a Vote of Security Holders.

Not applicable.

37

----

PART II

|              |                                                                                                             |
|--------------|-------------------------------------------------------------------------------------------------------------|
| Item5.  | Market for Registrant's Common Equity,Related Stockholder Matters and Issuer Purchases of EquitySecurities. |

Since March 14, 2000, MEHC's equitysecurities have been owned by Berkshire Hathaway, Walter Scott, Jr.(together with certain of his family members and family trusts andcorporations), David L. Sokol and Gregory E. Abel and have not beenregistered with the SEC pursuant to the Securities Act of 1933, asamended, listed on a stock exchange or otherwise publicly held ortraded.

Item 6.    Selected Financial Data.

Thefollowing table sets forth selected consolidated financial data, whichshould be read in conjunction with the Company's financialstatements and the related notes to those statements included in thisannual report and with "Item 7. Management'sDiscussion and Analysis of Financial Condition and Results ofOperations" appearing elsewhere in this annual report. Theselected consolidated financial data, as of and for the years endedDecember 31, 2003, 2002 and 2001, as of December 31, 2000 and for theperiods from March 14, 2000 through December 31, 2000, have beenderived from the Company's historical consolidated financialstatements. The selected consolidated financial data, from January 1,2000 through March 13, 2000 and as of and for the year ended December31, 1999, have been derived from MEHC Predecessor's historicalconsolidated financial statements.

SELECTED CONSOLIDATEDFINANCIAL DATA(Amounts in millions)

|                                                                                     |  |                                                |          |                                        |  |                                           |          |        |  |        |          |         |  |        |          |        |  |        |         |        |  |        |          |        |  |  |
|-------------------------------------------------------------------------------------|--|------------------------------------------------|----------|----------------------------------------|--|-------------------------------------------|----------|--------|--|--------|----------|---------|--|--------|----------|--------|--|--------|---------|--------|--|--------|----------|--------|--|--|
|                                                                                |  |     YearEnded December 31, |          | March 14,2000throughDecember31,2000(3) |  |     MEHC(Predecessor) |
|                                                                                |  | January1, 2000throughMarch 13,2000(4)          |          | Year EndedDecember31,1999(5)           |  |                                           |
|                                                                                |  | 2003                                           |          | 2002(1)                                |  | 2001(2)                                   |          |
| **Statementof OperationsData:**                                                     |  |                                           |     |                                   |  |                                      |     |   |  |   |     |    |  |   |     |   |  |   |    |   |  |   |     |   |
| Totalrevenue                                                                        |  | $                                              | 6,144.7  |                                   |  | $                                         | 4,968.1  |   |  | $      | 4,973.0  |    |  | $      | 4,013.0  |   |  | $      | 1,075.8 |   |  | $      | 4,368.5  |   |
| Totalcosts andexpenses                                                              |  |                                           | 5,294.9  |                                   |  |                                      | 4,325.0  |   |  |   | 4,469.1  |    |  |   | 3,793.8  |   |  |   | 984.7   |   |  |   | 4,011.5  |   |
| Incomebefore change in accountingprinciple                                          |  |                                           | 415.6    |                                   |  |                                      | 380.0    |   |  |   | 147.3    |    |  |   | 81.3     |   |  |   | 51.3    |   |  |   | 167.2    |   |
| Cumulativeeffect of change in accounting principle, net oftax                       |  |                                           | —  |                                   |  |                                      | —  |   |  |   | (4.6     | )  |  |   | —  |   |  |   | — |   |  |   | —  |   |
| Netincome                                                                           |  | $                                              | 415.6    |                                   |  | $                                         | 380.0    |   |  | $      | 142.7    |    |  | $      | 81.3     |   |  | $      | 51.3    |   |  | $      | 167.2    |   |
|                                                                                |  |                                           |     |                                   |  |                                      |     |   |  |   |     |    |  |   |     |   |  |   |    |   |  |   |     |   |
| **BalanceSheetData:**                                                               |  |                                           |     |                                   |  |                                      |     |   |  |   |     |    |  |   |     |   |  |   |    |   |  |   |     |   |
| Totalassets(6)                                                                      |  | $                                              | 19,168.2 |                                   |  | $                                         | 18,434.9 |   |  | $      | 12,994.6 |    |  | $      | 11,960.4 |   |  |   | N/A     |   |  | $      | 11,084.8 |   |
| Parentcompany seniordebt(7)                                                         |  |                                           | 2,777.9  |                                   |  |                                      | 2,323.4  |   |  |   | 1,834.5  |    |  |   | 1,830.0  |   |  |   | N/A     |   |  |   | 1,856.3  |   |
| Parentcompany subordinateddebt(7)                                                   |  |                                           | 1,772.1  |                                   |  |                                      | —  |   |  |   | —  |    |  |   | —  |   |  |   | — |   |  |   | —  |   |
| Company-obligatedmandatory redeemable preferred securities of subsidiarytrusts      |  |                                           | —  |                                   |  |                                      | 2,063.4  |   |  |   | 788.2    |    |  |   | 786.5    |   |  |   | N/A     |   |  |   | 450.0    |   |
| Subsidiaryand projectdebt(7)                                                        |  |                                           | 6,674.6  |                                   |  |                                      | 7,077.1  |   |  |   | 4,754.8  |    |  |   | 3,398.7  |   |  |   | N/A     |   |  |   | 3,642.7  |   |
| Subsidiary-obligatedmandatorily redeemable preferred securities of subsidiarytrusts |  |                                           | —  |                                   |  |                                      | —  |   |  |   | 100.0    |    |  |   | 100.0    |   |  |   | N/A     |   |  |   | 101.6    |   |
| Preferredsecurities ofsubsidiaries                                                  |  |                                           | 92.1     |                                   |  |                                      | 93.3     |   |  |   | 121.2    |    |  |   | 145.7    |   |  |   | N/A     |   |  |   | 146.6    |   |
| Totalstockholders'equity                                                            |  |                                           | 2,771.4  |                                   |  |                                      | 2,294.3  |   |  |   | 1,708.2  |    |  |   | 1,576.4  |   |  |   | N/A     |   |  |   | 994.6    |   |
|                                                                                     |

|  |
|--|
|  |  |
|  |

| (1) | Reflectsthe acquisitions of Kern River on March 27, 2002 and Northern NaturalGas on August  16, 2002. |
|-----|-------------------------------------------------------------------------------------------------------|

38

----

| (2) | Reflects the YorkshireSwap on September 21, 2001 and includes $15.2 million of after taxincome related to the sale of the Northern Electric electricity and gassupply business, the sale of the Telephone Flat Project, the sale ofWestern States Geothermal, the transfer of Bali Energy Ltd. shares, andthe Teesside Power Limited ("TPL") assetvaluation impairment charge. |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (3) | Reflects theTeton Transaction on March 14,2000. |
|-----|-------------------------------------------------|

| (4) | Includes $7.6 million of expensesrelated to the Teton Transaction. |
|-----|--------------------------------------------------------------------|

| (5) | ReflectsMEHC's acquisition of MidAmerican Energy on March 12, 1999,MEHC's disposition of the Coso Joint Ventures on February 26,1999, and MEHC's disposition of a 50% ownership interestin CE Generation on March 3, 1999 and includes $81.5 million of aftertax income related to the settlement of political risk insuranceproceeds related to MEHC's investment in Indonesia, gains onsales of shares of McLeodUSA, CE Electric UK restructuring charges andtransaction costs related to MEHC's acquisition by a privateinvestor group. |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (6) | The Company originally filedits Annual Report on Form 10-K on February 9, 2004. In accordance withaccounting guidance issued subsequent to that date, the Company hasreclassified regulatory liabilities for the cost of removal of utilityplant previously recognized within accumulated depreciation in theamounts of $385.7 million, $367.9 million, $349.5 million and $318.4million, as of December 31, 2002, 2001, 2000 and 1999, respectively, asan other long-term accrued liability. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (7) | Excludes current portion. |
|-----|---------------------------|

|              |                                                                                       |
|--------------|---------------------------------------------------------------------------------------|
| Item7.  | Management's Discussion and Analysis ofFinancial Condition and Results of Operations. |

Thefollowing discussion and analysis should be read in combination withthe selected consolidated financial data and the consolidated financialstatements included in Items 6 and 8 herein.

General

MEHC is a United States-based privately owned global energy companywith publicly held fixed income securities that generates, distributesand supplies energy to utilities, government entities, retail customersand other customers located throughout the world. Through itssubsidiaries, its operations are organized and managed on sevendistinct platforms: MidAmerican Energy, Kern River, Northern NaturalGas, CE Electric UK (which includes Northern Electric and Yorkshire),CalEnergy Generation-Domestic, CalEnergy Generation-Foreign andHomeServices.

Through these platforms, the Company owns andoperates a combined electric and natural gas utility company in theUnited States, two natural gas pipeline companies in the United States,two electricity distribution companies in the United Kingdom, adiversified portfolio of domestic and international independent powerprojects and the second largest residential real estate brokerage firmin the United States.

The Company's principal energysubsidiaries generate, transmit, store, distribute and supply energy.The Company's electric and natural gas utility subsidiariescurrently serve approximately 4.4 million electricity customers andapproximately 670,000 natural gas customers. Its natural gas pipelinesubsidiaries operate interstate natural gas transmission systems withapproximately 18,200 miles of pipeline in operation and peak deliverycapacity of 6.2 Bcf of natural gas per day. The Company has interestsin 6,716 net owned MW of power generation facilities in operation andconstruction, including 5,142 net owned MW in facilities that are partof the regulated return asset base of its electric utility business and1,574 net owned MW in non-utility power generation facilities.Substantially all of the non-utility power generation facilities havelong-term contracts for the sale of energy and/or capacity from thefacilities.

During the past several years, the Company completeda number of significant transactions, including thefollowing:

|              |                                                                                                                                                                                                                                                                                                         |
|--------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| •  | Northern Natural Gas wasacquired in August 2002 for $882.7 million, net of cash acquired.Northern Natural Gas owns a 16,500 mile interstate natural gas pipelineextending from southwest Texas to the upper Midwest region of theUnited States with a design capacity of 4.4 Bcf of natural gas perday. |

39

----

|              |                                                                                                                                                                                                                                                                                                                                              |
|--------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| •  | KernRiver was acquired in March 2002 for $419.7 million, net of cashacquired. At the date of acquisition, Kern River owned 926 miles ofinterstate natural gas pipeline extending from Wyoming to markets inCalifornia, Nevada and Utah and with access to natural gas suppliesfrom large producing regions in the Rocky Mountains andCanada. |

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

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

|              |                                                       |
|--------------|-------------------------------------------------------|
| •  | CE Casecnan commencedoperations on December 11, 2001. |

|              |                                                                                                                                                                                                                                                                                               |
|--------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| •  | OnSeptember 2001, CE Electric UK acquired 94.75% of Yorkshire fromInnogy Holdings plc and simultaneously sold Northern Electric'selectricity and gas supply and metering businesses to Innogy Holdingsplc. In August 2002, CE Electric UK acquired the remaining 5.25%of Yorkshire from Xcel. |

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

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

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

The increase was mainly due to: improvedearnings at MidAmerican Energy, higher income at Kern River primarilydue to the transportation fees earned in connection with the 2003Expansion Project and, to a lesser degree, the inclusion of itsoperations for all of 2003, the acquisition of Northern Natural Gas inAugust 2002 and the inclusion of its operations for all of 2003, higherincome at CE Electric UK due to lower costs and a weaker U.S. dollarand continued improvement at HomeServices due to acquisitions madethroughout 2002 and 2003 and growth at existing companies which benefitfrom the low interest rate environment, a related increase in themortgage refinance business and strong housing market. Offsetting thosebenefits 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 inconnection 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 $4,794.0million for the same period in 2002. The following table summarizesoperating revenue by segment for the years ended December 31 (inmillions):

|                                     |  |                      |         |         |  |         |         |         |  |        |         |         |  |  |
|-------------------------------------|--|----------------------|---------|---------|--|---------|---------|---------|--|--------|---------|---------|--|--|
|                                |  | YearEndedDecember31, |         |
|                                |  | 2003                 |         | 2002    |  | $Change |
| **Operatingrevenue:**               |  |                 |    |    |  |    |    |    |  |   |    |    |
| MidAmericanEnergy                   |  | $                    | 2,600.2 |    |  | $       | 2,240.9 |    |  | $      | 359.3   |    |
| KernRiver                           |  |                 | 260.2   |    |  |    | 127.3   |    |  |   | 132.9   |    |
| NorthernNaturalGas                  |  |                 | 482.2   |    |  |    | 176.9   |    |  |   | 305.3   |    |
| CEElectricUK                        |  |                 | 830.0   |    |  |    | 795.4   |    |  |   | 34.6    |    |
| CalEnergyGeneration –Domestic |  |                 | 45.8    |    |  |    | 38.5    |    |  |   | 7.3     |    |
| CalEnergyGeneration –Foreign  |  |                 | 326.4   |    |  |    | 326.3   |    |  |   | 0.1     |    |
| HomeServices                        |  |                 | 1,476.6 |    |  |    | 1,138.3 |    |  |   | 338.3   |    |
| Segmentoperatingrevenue             |  |                 | 6,021.4 |    |  |    | 4,843.6 |    |  |   | 1,177.8 |    |
| Corporate/other                     |  |                 | (73.2   | )  |  |    | (49.6   | )  |  |   | (23.6   | )  |
| Totaloperatingrevenue               |  | $                    | 5,948.2 |    |  | $       | 4,794.0 |    |  | $      | 1,154.2 |    |
|                                     |

MidAmericanEnergy's regulated and non-regulated gas revenue for the yearended December 31, 2003 increased $308.4 million to $1,112.7 millionfrom $804.3 million in 2002 mainly due to higher prices for gaspurchased for regulated customers which is passed directly to thecustomer. Average gas prices increased 59.9% or $2.24 per MMBtufrom 2002 to 2003. Regulated electric revenue for the year ended

40

----

December 31, 2003 increased $44.6 million to$1,398.0 million from $1,353.4 million for the same period in 2002mainly due to higher prices of off-system sales during 2003.

Operating revenue at both pipelines is principally derived byproviding firm or interruptible transportation services under long-termgas transportation service agreements. Northern Natural Gas alsoderives part of its revenue from storing gas. The increase in KernRiver's operating revenue was primarily due to the transportationfees earned in connection with the 2003 Expansion Project which beganoperations May 1, 2003, and to a lesser degree, the inclusion of itsoperations for all of 2003. Northern Natural Gas was acquired on August16, 2002. The increase in its operating revenue relates to the timingof that acquisition and inclusion of its operations for all of2003.

CE Electric UK operating revenue increased during 2003 asa result of the weaker U. S. dollar, higher distribution revenue andhigher revenue at its contracting business. This was partially offsetby lower revenue caused by the sale of CE Gas assets in 2002.

HomeServices' operating revenue, consisting mainly ofcommission 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% from151,808 closed sides in 2002. Closed brokerage volume was $48.6 billionin 2003, up 31.7% from $36.9 billion in 2002.

Income onequity investments for the year ended December 31, 2003 decreased $2.3million to $38.2 million from $40.5 million for the same period in2002. Equity income from non-regulated generation equity investmentsdecreased $16.6 million to $14.8 million from $31.4 million in 2002mainly due to the expiration of a contract at an independent powerplant and a charge associated with an equity investment. Equity incomefrom HomeServices for the year ended December  31, 2003 increased$14.8 million to $23.6 million from $8.8 million for the same period in2002 primarily due to increased refinancing activity at mortgage jointventures.

Interest and dividend income for the year endedDecember 31, 2003 decreased $8.4 million to $47.9 million from $56.3million for the same period in 2002. The decrease was primarily due tolower income at CE Electric UK of $9.9 million due to lower cashbalances following the redemption of the YED trust securities in June2003 partially offset by higher dividend income on the investment inWilliams' Cumulative Convertible Preferred Stock totaling $4.7million and interest earned on higher corporate cash balances availableduring 2003.

Other income for the year ended December 31, 2003increased $32.9 million to $110.3 million from $77.4 million in 2002.Other income in 2003 resulted mainly from a $31.9 million gainrecognized in connection with the NIA Arbitration settlement, equityAFUDC of $26.0 million, $13.8 million gain on sale of Williams'Cumulative Convertible Preferred Stock in June 2003 and $12.7 millionof income at CE Electric UK mainly from the gain on sale of a localoperational and dispatch facility at NED. Other income in 2002 resultedprimarily from the gain on the sale of CE Gas assets of $54.3 millionand equity AFUDC of $19.8 million. These items were offset, in 2002, bylosses from the write-down of non-regulated investments at MidAmericanEnergy of $21.9 million.

Cost of sales for the year endedDecember 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 millionfrom $988.9 million for the same period in 2002. MidAmerican Energyregulated and non-regulated gas cost of sales for the year endedDecember 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 ofgas discussed in operating revenue. Electric cost of sales increased$51.0 million in 2003 primarily due to the reclassification of costsfor energy purchased under the Cooper Nuclear Station restructuredcontract between MidAmerican Energy and the Nebraska Public PowerDistrict which expires in December 2004. Prior to August 1, 2002, thedate of the restructuring, only fuel costs for energy purchased fromCooper Nuclear Station were classified as a cost of sales. Consistentwith the restructured contract, other costs under the contract areclassified as operating expenses. Following the restructuring, allcosts for energy and capacity purchased under the contract wereincluded in cost of sales consistent with the new power purchasecontract. Operating expenses decreased accordingly.

41

----

HomeServices cost of sales, consistingprimarily of commissions on real estate brokerage transactions,increased $235.6 million for the year ended December 31, 2003, or30.7%, to $1,003.2 million from $767.6 million for the sameperiod in 2002. Cost of sales increased $178.8 million due toacquisitions made during 2002 and 2003. The remainder ofHomeServices' increase was due to growth of existing companiestotaling $56.8 million.

Operating expenses for the year endedDecember 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. Anincrease of $146.6 million was due to Northern Natural Gas, which wasowned for the entire period in 2003. Increased operating expenses atHomeServices were $78.8 million, primarily due to the impact ofacquisitions and increased compensation expenses. These increases werepartially offset by lower operating expenses at CE Electric UK of $30.7million primarily due to the sale of the retail business in 2002, loweroperating 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 loweroperating expenses at MidAmerican Energy of $19.5 million primarily dueto the restructuring of the Cooper contract.

Depreciation andamortization for the year ended December 31, 2003 increased $84.0million, or 16.0%, to $609.9 million from $525.9 million for thesame period in 2002. An increase of $34.6 million was due to NorthernNatural Gas, which was owned for the entire period in 2003. Increaseddepreciation at Kern River was $19.6 million mainly due to thecompletion of the 2003 Expansion Project and the inclusion of KernRiver's operations for the entire period. Increased depreciationof $11.6 million at MidAmerican Energy due to higher utility plantdepreciation and increased depreciation of $8.2 million at CE ElectricUK due to a weaker U.S. dollar and an increased asset base, partiallyoffset by the CE Gas asset sale in 2002.

Interest expense, lessamounts capitalized, for the year ended December 31, 2003 increased$131.4 million to $741.3 million from $609.9 million for the sameperiod in 2002. The increase was mainly due to interest on parentcompany subordinated debt which was $49.8 million for the quarter andyear ended December  31, 2003. This amount represents theinterest recorded on the parent company subordinated debt for theperiod from October 1, 2003, the date the Company adopted FASBInterpretation No. 46R, "Consolidation of VariableInterest Entities" ("FIN 46R"),through December 31, 2003. Prior to the adoption of FIN 46R, the parentcompany subordinated debt was classified as company-obligatedmandatorily redeemable preferred securities of subsidiary trusts. Costsassociated with those instruments, prior to the adoption of FIN 46R,were classified as minority interest and preferred dividends in theaccompanying consolidated statements of operations. In addition,increases resulted from additional interest expense totaling $38.9million on MEHC's debt issuances of $700.0 million in October2002 and $450.0 million in May 2003, increased interest expense of$32.5 million at Northern Natural Gas primarily due to a full year ofownership and increased interest expense at Kern  River of $32.2million due to additional borrowings related to the 2003 ExpansionProject and a full year of ownership. The increases were partiallyoffset by decreased interest, totaling $27.9 million, due to thecombination of the June 2003 redemption of the YED securities,reductions in CalEnergy Generation – Foreign project debt,MEHC's revolving credit facility and the retirement ofMEHC's 6.96% Senior Notes.

Provision for income taxfor the year ended December 31, 2003 increased $151.4 million to $251.0million from $99.6 million for the same period in 2002. The effectivetax rate was 29.5% and 15.5% for the years ended December31, 2003 and 2002, respectively. The increase in the effective tax ratewas primarily due to increased tax expense on foreign income includingthe incremental tax expense of $24.4 million in connection with the CECasecnan NIA Arbitration settlement proceeds. The 2002 effective taxrate was unusually low as the Company recognized tax benefits of $35.7million in connection with the execution of the TPL restructuringagreement at CE Electric UK.

Minority interest and preferreddividends for the year ended December 31, 2003 increased $19.7 millionto $183.2 million from $163.5 million for the same period in 2002. Theincrease in minority interest and preferred dividends is primarily dueto the issuance of Company-obligated mandatorily redeemable preferredsecurities of subsidiary trusts relating to the Kern River and NorthernNatural Gas acquisitions. This increase was partially offset by theadoption of FIN 46R described above and reduced dividends on subsidiarypreferred securities resulting from lower outstanding balances.

42

----

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

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

The increase wasmainly due to: acquisitions of Kern River in March 2002 and NorthernNatural Gas in August 2002, increased income at CE Electric UK,primarily as a result of the gain on the sale of CE Gas assets,increased income at CalEnergy Generation – Foreign due to a fullyear of operations of the CE Casecnan project, improved earnings atMidAmerican Energy's regulated electric business and continuedimprovement at HomeServices due to acquisitions made throughout 2002and growth at existing companies.

Operating revenue for the yearended 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 theyears ended December 31 (in  millions):

|                                     |  |                      |         |         |  |         |         |         |  |        |        |         |  |  |
|-------------------------------------|--|----------------------|---------|---------|--|---------|---------|---------|--|--------|--------|---------|--|--|
|                                |  | YearEndedDecember31, |         |
|                                |  | 2002                 |         | 2001    |  | $Change |
| **Operatingrevenue:**               |  |                 |    |    |  |    |    |    |  |   |   |    |
| MidAmericanEnergy                   |  | $                    | 2,240.9 |    |  | $       | 2,388.7 |    |  | $      | (147.8 | )  |
| KernRiver                           |  |                 | 127.3   |    |  |    | — |    |  |   | 127.3  |    |
| NorthernNaturalGas                  |  |                 | 176.9   |    |  |    | — |    |  |   | 176.9  |    |
| CEElectricUK                        |  |                 | 795.4   |    |  |    | 1,444.0 |    |  |   | (648.6 | )  |
| CalEnergyGeneration –Domestic |  |                 | 38.5    |    |  |    | 37.3    |    |  |   | 1.2    |    |
| CalEnergyGeneration –Foreign  |  |                 | 326.3   |    |  |    | 203.5   |    |  |   | 122.8  |    |
| HomeServices                        |  |                 | 1,138.3 |    |  |    | 641.9   |    |  |   | 496.4  |    |
| Segmentoperatingrevenue             |  |                 | 4,843.6 |    |  |    | 4,715.4 |    |  |   | 128.2  |    |
| Corporate/other                     |  |                 | (49.6   | )  |  |    | (18.6   | )  |  |   | (31.0  | )  |
| Totaloperatingrevenue               |  | $                    | 4,794.0 |    |  | $       | 4,696.8 |    |  | $      | 97.2   |    |
|                                     |

MidAmericanEnergy regulated and non-regulated gas revenue decreased due to lowerprices for gas purchased which is passed directly to the customer,partially offset by an increase in regulated electric retail sales forthe year ended December 31, 2002 as compared to 2001 due primarily tohigher relative temperatures in 2002, which occurred primarily in thethird quarter of 2002.

Kern River and Northern Natural Gas wereacquired in March 2002 and August 2002, respectively. The increasesrelate to their inclusion in MEHC's operations in 2002.

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

CalEnergyGeneration – Foreign operating revenue for the year endedDecember 31, 2002 increased primarily due to commencement of commercialoperation of the Casecnan project in December 2001.

HomeServicesoperating revenue for the year ended December 31, 2002 increasedprimarily due to contributions from 2002 acquisitions of $431.5million. The remainder of HomeServices' increase was due togrowth of existing companies of $105.3 million partially offset by adecrease of $40.4 million from a joint venture that was consolidated in2001 and is accounted for under the equity method in 2002.

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

43

----

Other income for the year ended December31, 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 2002resulted primarily from the non-recurring gain on the sale of CE Gas of$54.3 million and equity AFUDC of $19.8 million. These items wereoffset, in 2002, by losses from the write-down of non-regulatedinvestments at MidAmerican Energy of $21.9 million. Other income in2001 resulted from the non-recurring gains from the sales of NorthernElectric's supply business, Telephone Flat and Western StatesGeothermal of $196.7 million, $20.7 million and $9.8 million,respectively, and a non-recurring gain from the transfer of Bali sharesof $10.4 million. These items were partially offset, in 2001, by acharge related to the impairment of the Company's interest in TPLof $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 Energycost of sales for the year ended December 31, 2002 decreased $132.4million or 11.8% to $988.9 million from $1,121.3 million for thesame period in 2001, primarily due to decreases in regulated andnon-regulated gas costs, caused by lower volumes and prices, partiallyoffset by an increase in regulated electric costs caused by highervolumes, partially offset by the restructuring of the Cooper NuclearStation contract.

CE Electric UK cost of sales for the yearended December 31, 2002 decreased $713.2 million or 84.6% to$129.5 million from $842.7 million for the same period in 2001. Thedecrease was primarily due to the sale of the supply business in2001.

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 primarilydue to costs at companies acquired during 2002 of $315.6 million, andhigher commission expense resulting from increased sales at existingHomeServices businesses.

Operating expenses for the year endedDecember 31, 2002 increased $168.8 million or 14.3% to $1,345.2million from $1,176.4 million for the same period in 2001. The increasewas primarily due to higher costs at HomeServices of $99.1 million as aresult of acquisitions, operating expenses due to the acquisitions ofNorthern Natural Gas of $95.0 million and Kern River of $27.2 millionand plant operating expenses at the Zinc project and CE Casecnan of$33.9 million, partially offset by lower costs at MidAmerican Energy of$57.5 million primarily due to the restructuring of the Cooper NuclearStation contract and lower energy efficiency expenses and lower costsat CE Electric UK of $28.5 million due to the sale of the supplybusiness.

Depreciation and amortization for the year endedDecember 31, 2002 decreased $12.8 million or 2.4% to $525.9million from $538.7 million for the same period in 2001. The decreasewas primarily due to discontinuance of amortizing goodwill beginningJanuary 1, 2002 of $96.4 million, partially offset by a full year ofoperations at CE Casecnan of $22.0 million, higher depreciation atMidAmerican Energy of $17.2 million primarily due to higher Iowarevenue sharing accruals and a change in the estimated useful lives ofelectric generation plant, depreciation expense due to the acquisitionsof Kern River of $17.2 million and Northern Natural Gas of $18.2million and increased amortization at HomeServices of $9.5 millionprimarily due to the amortization of the gross margin of pending salescontracts related to acquisitions.

Interest expense, lessamounts capitalized, for the year ended December 31, 2002 increased$197.1 million or 47.7% to $609.9 million from $412.8 millionfor the same period in 2001. The increase was primarily due to theincrease of interest expense at CE Electric UK of $71.3 millionpredominantly due to the debt acquired as part of the Yorkshireacquisition, interest expense due to debt related to the acquisitionsof Kern River and Northern Natural Gas of $33.0 million and $23.0million, respectively and the discontinuance of capitalizing interestrelated to the Casecnan project, the Cordova project and the ZincRecovery project of $50.9 million, $9.4 million and $5.3 million,respectively, all partially offset by capitalized interest at KernRiver of $14.0 million.

Tax expense for the year ended December31, 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 was15.5% and 49.6% for the years ended December 31, 2002 and2001, respectively. The decrease is due primarily to the tax expenserelated 

44

----

to the sale of the Northern Electric supplybusiness in September 2001, the release of the tax obligation of $35.7million in connection with the execution of the TPL restructuringagreement at CE Electric UK in 2002, and the recognition of a taxbenefit in connection with the sale of the CE Gas assets in 2002.

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

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

Liquidity and Capital Resources

The Company hasavailable a variety of sources of liquidity and capital resources, bothinternal and external. These resources provide funds required forcurrent operations, construction expenditures, debt retirement andother capital requirements. The Company may from time to time seek toretire its outstanding debt through cash purchases in the open market,privately negotiated transactions or otherwise. Such repurchases orexchanges, if any, will depend on prevailing market conditions, theCompany's liquidity requirements, contractual restrictions andother factors. The amounts involved may be material.

TheCompany's cash and cash equivalents were $660.2 million atDecember 31, 2003, compared to $844.4 million at December 31, 2002.Each of MEHC's direct or indirect subsidiaries is organized as alegal entity separate and apart from MEHC and its other subsidiaries.Pursuant to separate financing agreements at each subsidiary, theassets of each subsidiary may be pledged or encumbered to support orotherwise provide the security for their own project or subsidiarydebt. It should not be assumed that any asset of any subsidiary of MEHCwill be available to satisfy the obligations of MEHC or any of itsother subsidiaries; provided, however, that unrestricted cash or otherassets which are available for distribution may, subject to applicablelaw and the terms of financing arrangements for such parties, beadvanced, loaned, paid as dividends or otherwise distributed orcontributed to MEHC or affiliates thereof.

In addition, theCompany recorded separately, in restricted cash and short-terminvestments and in deferred charges and other assets, restricted cashand investments of $119.5 million and $58.7 million at December 31,2003, and December 31, 2002, respectively. The restricted cash balancefor both periods is comprised primarily of amounts deposited inrestricted accounts which are reserved for the service of debtobligations and customer deposits held in escrow.

Cash flowsfrom Operating Activities

The Company generated cash flows fromoperations of $1,217.9 million for the year ended December 31, 2003,compared with $757.7 million for the same period in 2002. The increasewas mainly due to the positive impacts of the Kern River, NorthernNatural Gas and HomeServices' acquisitions as well as acceleratedtax depreciation benefits.

Cash Flows from InvestingActivities

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

45

----

Capital Expenditures, Constructionand Other Development Costs

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

|                                      |  |                       |         |        |  |        |         |        |  |  |
|--------------------------------------|--|-----------------------|---------|--------|--|--------|---------|--------|--|--|
|                                 |  | YearEnded December31, |
|                                 |  | 2003                  |         | 2002   |
| MidAmericanEnergy                    |  | $                     | 378.5   |   |  | $      | 358.2   |   |
| KernRiver                            |  |                  | 361.5   |   |  |   | 769.5   |   |
| Northern NaturalGas                  |  |                  | 104.4   |   |  |   | 62.4    |   |
| CE ElectricUK                        |  |                  | 301.9   |   |  |   | 222.6   |   |
| CalEnergy Generation– Domestic |  |                  | 17.9    |   |  |   | 61.9    |   |
| CalEnergyGeneration –Foreign   |  |                  | 8.5     |   |  |   | 7.8     |   |
| HomeServices                         |  |                  | 18.3    |   |  |   | 18.3    |   |
| Segmentcapitalexpenditures           |  |                  | 1,191.0 |   |  |   | 1,500.7 |   |
| Corporate/other                      |  |                  | 0.1     |   |  |   | 7.4     |   |
| Totalcapitalexpenditures             |  | $                     | 1,191.1 |   |  | $      | 1,508.1 |   |
|                                      |

Capitalexpenditures and construction and other development costs for 2004 areexpected to be approximately $1.3 billion.

MidAmerican EnergyCapital Expenditures, Construction and Development Costs

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

Forecasted utility construction expenditures, including allowancefor funds used during construction, are $844 million for 2004. Capitalexpenditure needs are reviewed regularly by management and may changesignificantly as a result of such reviews. MidAmerican Energy expectsto meet these capital expenditures with cash flows from operations andthe issuance of long-term debt.

In order to address projectedcapacity needs for its regulated customers, MidAmerican Energy iscurrently constructing two electric generating projects in Iowa anddeveloping a third. Upon completion, the projects will provide serviceto regulated retail electricity customers. MidAmerican Energy hasobtained regulatory approval to include the actual costs of thegeneration projects in its Iowa rate base as long as actual costs donot exceed an agreed upon cap that MidAmerican Energy has deemed to bereasonable. Wholesale sales may also be made from the projects to theextent the power is not needed for regulated retail service.MidAmerican Energy expects to invest approximately $1.4 billion in thethree projects, of which approximately $314 million has been investedthrough December 31, 2003.

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

The second project iscurrently under construction and is a 790 MW (based on expectedaccreditation) super-critical-temperature, low-sulfur coal-fired plant.MidAmerican Energy will operate the plant and hold an undividedownership interest as a tenant in common with the other owners of theplant. MidAmerican Energy's ownership interest is 60.67%,equating to 479 MW of output. MidAmerican Energy expects its share ofthe 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 isa typical ownership arrangement for large base-load plants in Iowa. OnMay 29, 2003, the IUB issued an order that approves the ratemakingprinciples for the plant, and on June 27, 2003, MidAmerican Energyreceived a certificate from the IUB allowing MidAmerican Energy toconstruct the 

46

----

plant. On February 12, 2003, MidAmericanEnergy executed a contract with Mitsui for the engineering, procurementand construction of the plant. On September 9, 2003, MidAmerican Energybegan construction of the plant, which it expects to be completed inthe summer of 2007. MidAmerican Energy is also seeking an order fromthe IUB approving construction of the associated transmissionfacilities.

The third project is currently under development andis comprised of wind power facilities totaling 310 MW based on thenameplate rating. Generally speaking, accredited capacity ratings forthe wind power facilities are considerably less than the nameplateratings due to the varying nature of wind. The current projectedaccredited capacity for these wind power facilities is approximately 53MW. If constructed, MidAmerican Energy will own and operate thesefacilities, which are expected to cost approximately $323 million.MidAmerican Energy's plan to construct the wind project is inconjunction with a settlement agreement that extends through December31, 2010, an Iowa retail electric rate freeze that was previouslyscheduled to expire at the end of 2005. The settlement agreement, whichwas filed with the IUB as part of MidAmerican Energy'sapplication for ratemaking principles for the wind project, wasapproved by the IUB on October 17, 2003. The obligation of MidAmericanEnergy to construct the wind project may be terminated by MidAmericanEnergy if the federal production tax credit applicable to the windenergy facilities is not available at a rate of 1.8 cents per kWh for aperiod of at least ten years after the facilities begin generatingelectricity. The production tax credit is available only to windfacilities placed in service before January 1, 2004. MidAmerican Energyhas also received authorization from the IUB to construct the windpower project. If MidAmerican Energy does not construct the windfacilities by December 31, 2007, the rate extension from January 1,2006 through December 31, 2010 may terminate.

KernRiver's 2003 Expansion Project

On May 1, 2003, Kern Rivercompleted the construction of its 2003 Expansion Project at a totalcost of approximately $1.2 billion. The expansion increased the designcapacity of the existing Kern River pipeline by 885,626 Dth per day to1,755,626 Dth per day.

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

OtherDevelopment Costs

Obsidian is evaluating the development of a185 net MW geothermal facility in the Imperial Valley in California.Substantially all of the output of the facility would be sold to theIID pursuant to a power purchase agreement. TransAlta is currentlyfunding 50% of the development costs of this project. OnDecember  17, 2003, the CEC issued final approval forconstruction of the facility. If the project is constructed, MEHCexpects capital expenditures to total approximately $550.0 million andcurrently plans to fund its interest in this project with availablecash and future issuances of debt.

Acquisitions

Kern River

In March2002, MEHC acquired Kern River for $419.7 million, net of cash acquiredand a working capital adjustment. At the time, Kern River owned a926-mile interstate natural gas pipeline extending from Wyoming tomarkets in California, Nevada and Utah and accesses natural gassupplies from large producing regions in the Rocky Mountains andCanada. MEHC used the proceeds from the issuances of $323.0 million of11% Company-obligated mandatorily redeemable preferredsecurities of subsidiary trust due March 12, 2012 with scheduledprincipal payments beginning in 2005 and $127.0 million of no par, zerocoupon convertible preferred stock to Berkshire Hathaway to finance theacquisition.

Northern Natural Gas

In August 2002, MEHCacquired Northern Natural Gas for $882.7 million, net of cash acquiredand a working capital adjustment. Northern Natural Gas owns a16,500-mile interstate natural gas pipeline 

47

----

extending from southwest Texas to the upperMidwest region of the United States with a design capacity of 4.4 Bcfof natural gas per day. Northern Natural Gas also operates threenatural gas storage facilities and two liquefied natural gas peakingunits with a total storage capacity of 59 Bcf and peak deliverycapability of over 1.3 Bcf of natural gas per day. Northern Natural Gasaccesses natural gas supply from many of the larger producing regionsin North America, including the Rocky Mountains, Hugoton, Permian,Anadarko and Western Canadian basins. The pipeline system providestransportation and storage services to utilities, municipalities, otherpipeline companies, gas marketers and industrial and commercial users.MEHC used the proceeds from a $950.0 million investment in itssubsidiary trust's preferred securities by Berkshire Hathaway tofinance the acquisition.

HomeServices' Acquisitions

In 2003, HomeServices separately acquired four real estate companiesfor an aggregate purchase price of approximately $36.7 million, net ofcash acquired, plus working capital and certain other adjustments. Forthe year ended December 31, 2002, these real estate companies hadcombined revenue of approximately $102.9 million on 16,000 closed sidesrepresenting $3.6 billion of sales volume. Additionally, HomeServicesis obligated to pay a maximum earnout of $5.2 million based on 2004 and2005 financial performance measures. These purchases were financedusing HomeServices' internally generated cash flows and revolvingcredit facility. In 2002, HomeServices separately acquired three realestate companies for an aggregate purchase price of approximately$106.1 million, net of cash acquired, plus working capital and certainother adjustments. For the year ended December 31, 2001, these realestate companies had combined revenue of approximately $356.0 millionon 42,000 closed sides representing $13.7 billion of sales volume.Additionally, HomeServices was obligated to pay an earnout of $17.3million based on 2002 financial performance measures. These purchaseswere financed using HomeServices' internally generated cashflows, revolving credit facility and $40.0 million from MEHC, which wascontributed to HomeServices as equity.

Williams'Cumulative Convertible Preferred Stock

On June 10,2003, Williams repurchased, for approximately $288.8 million, plusaccrued dividends, all of the shares of its 9-7/8% CumulativeConvertible Preferred Stock originally acquired by the Company in March2002 for $275.0 million.

Put of ROP Bond and Receipt ofCash

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

Cash Flows from Financing Activities

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

Recent Debt Issuancesand Redemptions

On January 14, 2003, MidAmericanEnergy issued $275.0 million of 5.125% medium-term notes due in2013. The proceeds were used to refinance existing debt and for othercorporate purposes.

On February 10, 2003, MidAmerican Energyredeemed all $75.0 million of its 7.375% series of mortgagebonds, and on March 17, 2003, it redeemed all $6.94 million of its7.45% series of mortgage bonds. Additionally, MidAmericanEnergy's 7.125% series of mortgage bonds totaling $100million matured on February 3, 2003. On October 17, 2003, MidAmericanEnergy redeemed all $12.5 million of its 6.95% series ofmortgage bonds at 103.48% of the principal amount.

48

----

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

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

On June 9, 2003, Yorkshire Power Group Limited, a whollyowned indirect subsidiary of CE Electric UK, completed the redemptionin full of the outstanding shares of the Yorkshire Capital Trust I,8.08% trust securities, due June 30, 2038, and paid $243.4million in principal amount ($25 liquidation amount per each trustsecurity) plus accrued distributions of $0.381555555 per trust securityto the redemption date. The redemption price was paid to holders of thetrust 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 originalface amount of debt obligations of its subsidiaries of which $37.5million is held in other investments with the remainder beingretired.

During 2003, CE Electric UK and its subsidiariespurchased and retired approximately $50 million of outstandingindebtedness.

On January 30, 2004, Salton Sea FundingCorporation ("SSFC"), a wholly ownedsubsidiary of CE Generation, announced its election to redeem anaggregate principal amount of approximately $136.4 million of its7.475% Senior Secured Series F Bonds due November 30, 2018, prorata, at a redemption price of 100% of such aggregateoutstanding principal amount, plus accrued interest to the date ofredemption. The trustee delivered a redemption notice to the holders ofthe bonds on January 29, 2004. The record date for the redemption isFebruary 15, 2004 and the redemption is expected to be completed onMarch 1, 2004. SSFC expects to make a demand on MEHC for the fullamount remaining on MEHC's guarantee of the Series F Bonds inorder to fund the redemption. Upon the expected demand and paymentunder MEHC's guarantee, MEHC will no longer have any liabilitywith respect to its guarantee.

Credit Ratings Risks

Debt and preferred securities of the Company may be rated bynationally recognized credit rating agencies. Assigned credit ratingsare based on each rating agency's assessment of the ratedcompany's ability to, in general, meet the obligations of itsdebt or preferred securities. The credit ratings are not arecommendation to buy, sell or hold securities, and there is noassurance that a particular credit rating will continue for any givenperiod of time. The Company does not have any credit agreements thatrequire termination or a material change in collateral requirements orpayment schedule in the event of a downgrade in the credit ratings ofthe respective company's securities.

In conjunction withits wholesale marketing and trading activities, MidAmerican Energy mustmeet credit quality standards as required by counterparties.MidAmerican Energy has energy trading agreements that, in accordancewith industry practice, either specifically require it to maintaininvestment grade credit ratings or provide the right for counterpartiesto demand "adequate assurances" in the eventof a material adverse change in MidAmerican Energy'screditworthiness. If one or more of MidAmerican Energy's creditratings decline below investment grade, MidAmerican Energy may berequired to post cash collateral, letters of credit or other similarcredit support to facilitate ongoing wholesale marketing and tradingactivities. As of December 31, 2003, MidAmerican Energy'sestimated potential collateral requirements totaled approximately $89million. MidAmerican Energy's collateral requirements couldfluctuate considerably due to seasonality, market price volatility, aloss of key MidAmerican Energy generating facilities or other relatedfactors.

Yorkshire Power Group Limited, a subsidiary of CEElectric UK, entered into certain currency rate swap agreements for itsYankee Bonds with three large multi-national financial institutions.The swap agreements effectively convert the U.S. dollar fixed interestrate to a fixed rate in Sterling. For the $281.1 million of the6.496% Yankee Bonds outstanding at December 31, 2003, theagreements extend until February 25, 2008 and convert the U.S. dollarinterest rate to a fixed Sterling rate ranging from 7.3175%

49

----

to 7.345%. The estimated fair valueof these swap agreements at December 31, 2003 is approximately $62.6million based on quotes from the counterparties to these instrumentsand represents the estimated amount that the Company would expect topay if these agreements were terminated. Certain of thesecounterparties have the option to terminate the swap agreements anddemand payment of the fair value of the swaps if Yorkshire Power GroupLimited's credit ratings from the three recognized credit ratingagencies decline below investment grade. As of December 31, 2003,Yorkshire Power Group Limited's credit ratings from the threerecognized credit rating agencies were investment grade; however, ifthe ratings fell below investment grade, payment requirements wouldhave been approximately $29.0 million.

Inflation

Inflation has not had a significant impact on the Company'scosts.

Obligations and Commitments

The Company hascontractual obligations and commercial commitments that may affect itsfinancial condition. Contractual obligations to make future paymentsarise from parent company and subsidiary long-term debt and notespayable, preferred equity securities, operating leases and power andfuel purchase contracts. Other obligations arise from unused lines ofcredit and letters of credit. Material obligations as of December 31,2003 are as follows (in millions):

|                                                          |  |                      |          |           |  |           |         |           |  |            |         |        |  |        |         |        |  |        |         |        |  |  |
|----------------------------------------------------------|--|----------------------|----------|-----------|--|-----------|---------|-----------|--|------------|---------|--------|--|--------|---------|--------|--|--------|---------|--------|--|--|
|                                                     |  | PaymentsDue ByPeriod |
|                                                     |  | Total                |          | <1Year |  | 2-3 Years |         | 4-5 Years |  | >5Years |
| Contractual CashObligations:                             |  |                 |     |      |  |      |    |      |  |       |    |   |  |   |    |   |  |   |    |   |
| Parentcompany seniordebt                                 |  | $                    | 2,777.9  |      |  | $         | — |      |  | $          | 260.0   |   |  | $      | 1,550.0 |   |  | $      | 967.9   |   |
| Parentcompany subordinateddebt                           |  |                 | 1,872.1  |      |  |      | 100.0   |      |  |       | 422.6   |   |  |   | 468.0   |   |  |   | 881.5   |   |
| Subsidiaryand project debt(1)                            |  |                 | 7,175.6  |      |  |      | 500.9   |      |  |       | 864.5   |   |  |   | 917.6   |   |  |   | 4,892.6 |   |
| Preferredsecurities ofsubsidiaries                       |  |                 | 92.1     |      |  |      | — |      |  |       | — |   |  |   | — |   |  |   | 92.1    |   |
| Coal,electricity and natural gas contract commitments(2) |  |                 | 593.1    |      |  |      | 179.0   |      |  |       | 204.5   |   |  |   | 101.2   |   |  |   | 108.4   |   |
| Operatingleases(2)                                       |  |                 | 290.1    |      |  |      | 53.1    |      |  |       | 87.9    |   |  |   | 64.1    |   |  |   | 85.0    |   |
| Totalcontractual cashobligations                         |  | $                    | 12,800.9 |      |  | $         | 833.0   |      |  | $          | 1,839.5 |   |  | $      | 3,100.9 |   |  | $      | 7,027.5 |   |
|                                                          |

|                                                |  |                                |        |           |  |           |         |           |  |            |        |        |  |        |         |        |  |        |         |        |  |  |
|------------------------------------------------|--|--------------------------------|--------|-----------|--|-----------|---------|-----------|--|------------|--------|--------|--|--------|---------|--------|--|--------|---------|--------|--|--|
|                                           |  | CommitmentExpiration perPeriod |
|                                           |  | Total                          |        | <1Year |  | 2-3 Years |         | 4-5 Years |  | >5Years |
| Other CommercialCommitments:                   |  |                           |   |      |  |      |    |      |  |       |   |   |  |   |    |   |  |   |    |   |
| Unusedparent company revolving lines of credit |  | $                              | 26.4   |      |  | $         | — |      |  | $          | 26.4   |   |  | $      | — |   |  | $      | — |   |
| Parent company letters ofcredit                |  |                           | 73.6   |      |  |      | 73.0    |      |  |       | 0.6    |   |  |   | — |   |  |   | — |   |
| Unusedsubsidiary lines ofcredit                |  |                           | 138.0  |      |  |      | 13.0    |      |  |       | 125.0  |   |  |   | — |   |  |   | — |   |
| Totalother commercialcommitments               |  | $                              | 238.0  |      |  | $         | 86.0    |      |  | $          | 152.0  |   |  | $      | — |   |  | $      | — |   |
|                                                |

|  |
|--|
|  |  |
|  |

| (1) | Total less thanone year includes $136.4 million expected to be redeemed on March 1,2004. |
|-----|------------------------------------------------------------------------------------------|

| (2) | The Coal, electricity and natural gascontract commitments and operating leases are not reflected on theconsolidated balance sheets. |
|-----|-------------------------------------------------------------------------------------------------------------------------------------|

Off-Balance SheetArrangements

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

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

50

----

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

MEHC is generally notrequired to support the debt service obligations of its equityinvestments. However, default with respect to this non-recourse debtcould result in a loss of invested equity.

New AccountingPronouncements

On January 1, 2003, the Company adopted SFAS No.143, "Accounting for Asset RetirementObligations". This statement provides accounting anddisclosure requirements for retirement obligations associated withlong-lived assets. The cumulative effect of initially applying thisstatement by the Company was immaterial.

The Company identifiedlegal retirement obligations for nuclear decommissioning, wet and dryash landfills and offshore and minor lateral pipeline facilities. OnJanuary 1, 2003, the Company recorded $289.3 million of assetretirement obligation ("ARO") liabilities;$13.9 million of ARO assets, net of accumulated depreciation; $114.6million of regulatory assets; and reclassified $1.0 million ofaccumulated depreciation to the ARO liability. The initial AROliability recognized includes $266.5 million that pertains toobligations associated with the decommissioning of the Quad Citiesnuclear station. The $266.5 million includes a $159.8 million nucleardecommissioning liability that had been recorded at December 31, 2002.The adoption of this statement did not have a material impact on theoperations of the regulated entities, as the effects were offset by theestablishment of regulatory assets, totaling $114.6 million, pursuantto SFAS No. 71, "Accounting for the Effects of CertainTypes of Regulation".

On April 30, 2003, the FASBissued SFAS No. 149, "Amendment of Statement 133 onDerivative Instruments and Hedging Activities"("SFAS 149"). SFAS 149 amends SFAS No. 133for derivative instruments, including certain derivative instrumentsembedded in other contracts and for hedging activities. SFAS 149requires contracts with comparable characteristics to be accounted forsimilarly. In particular, SFAS 149 clarifies when a contract with aninitial net investment meets the characteristic of a derivative andclarifies when a derivative that contains a financing component willrequire special reporting in the statement of cash flows. SFAS 149 iseffective for the Company for contracts entered into or modified afterJune 30, 2003. The adoption of SFAS 149 did not have a material effecton the Company's financial position, results of operations orcash flows.

In May 2003, the FASB issued SFAS No. 150,"Accounting for Certain Financial Instruments withCharacteristics of both Liabilities and Equity"("SFAS 150").   SFAS 150 establishedstandards for how an issuer classifies and measures certain financialinstruments with characteristics of both liabilities and equity. Itrequires that an issuer classify a financial instrument that is withinits scope as a liability (or an asset in some circumstances). Thestandard is effective for the Company for fiscal periods beginningafter December 15, 2003. The adoption of SFAS 150 is not expected tohave a material effect on the Company's financial position,results of operations or cash flows.

In December 2003, the FASBissued FIN 46R, which served to clarify guidance in FinancialInterpretation No. 46 ("FIN 46"), andprovided additional guidance surrounding the application of FIN 46. TheCompany adopted and applied the provisions of FIN 46R as of October 1,2003. The adoption required the deconsolidation of certain financesubsidiaries, which resulted in the amounts previously classified asmandatorily redeemable preferred securities of subsidiary trusts, ofapproximately $1.9 billion, being reclassified to parent companysubordinated debt in the accompanying consolidated balance sheet as ofDecember 31, 2003. In addition, the associated amounts previouslyrecorded as minority interest are now recorded as interest expense inthe accompanying consolidated statement of operations. For the periodfrom October 1, 2003 to December 31, 2003, the Company has recorded$49.8 million of interest expense related to these securities. Inaccordance with the requirements of FIN 46R, no amounts prior toadoption on October 1, 2003 have been reclassified. The Company willadopt the provisions of FIN 46R related to non-special purpose entitiesin the first quarter of 2004, in accordance with the 

51

----

provisions of FIN 46R. The Company iscurrently evaluating the impact of FIN 46R on several operating jointventures that the Company currently does not consolidate.

Critical Accounting Policies

The preparation of financialstatements and related documents in conformity with generally acceptedaccounting principles in the United States of America("GAAP") requires management to makejudgments, assumptions and estimates that affect the amounts reportedin the consolidated financial statements and accompanying notes. Note 2to the consolidated financial statements for the year ended December31, 2003 included in this annual report describes the significantaccounting policies and methods used in the preparation of theconsolidated financial statements. Estimates are used for, but notlimited to, the accounting for the effects of certain types ofregulation, impairment of long-lived assets, contingent liabilities,accrued pension and post-retirement expense and revenue. Actual resultscould differ from these estimates. The following critical accountingpolicies are impacted significantly by judgments, assumptions andestimates used in the preparation of the consolidated financialstatements.

Accounting for the Effects of Certain Types ofRegulation

MidAmerican Energy, Kern River and Northern NaturalGas prepare their financial statements in accordance with theprovisions of Statement of Financial Accounting Standards("SFAS") No. 71 ("SFAS71"), which differs in certain respects from theapplication of generally accepted accounting principles bynon-regulated businesses. In general, SFAS 71 recognizes thataccounting for rate-regulated enterprises should reflect the economiceffects of regulation. As a result, a regulated utility is required todefer the recognition of costs (a regulatory asset) or the recognitionof obligations (a regulatory liability) if it is probable that, throughthe rate-making process, there will be a corresponding increase ordecrease in future rates. Accordingly, MidAmerican Energy, Kern Riverand Northern Natural Gas have deferred certain costs, which will beamortized over various future periods. To the extent that collection ofsuch costs or payment of such obligations is no longer probable as aresult of changes in regulation, the associated regulatory asset orliability is charged or credited to income.

A possibleconsequence of deregulation of the regulated energy industry is thatSFAS 71 may no longer apply. If portions of the Company'sregulated energy operations no longer meet the criteria of SFAS 71, theCompany could be required to write off the related regulatory assetsand liabilities from its balance sheet, and thus a material adjustmentto earnings in that period could result if regulatory assets orliabilities are not recovered in transition provisions of anyderegulation legislation.

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

Impairment of Long-Lived Assets

The Company'slong-lived assets consist primarily of properties, plants and equipmentand acquired goodwill. Depreciation is computed using the straight-linemethod based on economic lives or regulatorily mandated recoveryperiods. The Company believes the useful lives assigned to thedepreciable assets, which generally range from 3 to 87 years, arereasonable.

The Company's periodically evaluateslong-lived assets, including properties, plants and equipment, whenevents or changes in circumstances indicate that the carrying value ofthese assets may not be recoverable. Upon the occurrence of atriggering event, the carrying amount of a long-lived asset is reviewedto assess whether the recoverable amount has declined below itscarrying amount. The recoverable amount is the estimated net futurecash flows that the Company expects to recover from the future use ofthe asset, undiscounted and without interest, plus the asset'sresidual value on disposal. Where the recoverable amount of thelong-lived asset is less than the carrying value, an impairment losswould be recognized to write down the asset to its fair value that isbased on discounted estimated cash flows from the future use of theasset. The Company also evaluates goodwill for impairment annually,primarily using a discounted cash flow methodology.

The estimateof cash flows arising from future use of the asset that are used in theimpairment analysis requires judgment regarding what the Company wouldexpect to recover from future use of the 

52

----

asset. Any changes in the estimates of cashflows arising from future use of the asset or the residual value of theasset on disposal based on changes in the market conditions, changes inthe use of the asset, management's plans, the determination ofthe useful life of the asset and technology changes in the industrycould significantly change the calculation of the fair value orrecoverable amount of the asset and the resulting impairment loss,which could significantly affect the results of operations. Thedetermination of whether impairment has occurred is based on anestimate of undiscounted cash flows attributable to the assets, ascompared to the carrying value of the assets. An impairment analysis ofgenerating facilities requires estimates of possible future marketprices, load growth, competition and many other factors over the livesof the facilities. A resulting impairment loss is highly dependent onthese underlying assumptions.

On January 1, 2002, the Companyadopted SFAS No. 142, "Goodwill and Other IntangibleAssets" ("SFAS 142"), whichestablishes the accounting for acquired goodwill and other intangibleassets, and provides that goodwill and indefinite-lived intangibleassets will not be amortized, but will be tested for impairment on anannual basis. The Company's related amortization consists solelyof goodwill amortization. In accordance with SFAS 142, the Companycompleted its annual goodwill impairment test, as of October 31, 2003,primarily using a discounted cash flow methodology. No impairment wasindicated as a result of the impairment tests.

ContingentLiabilities

The Company establishes reserves for estimated losscontingencies, such as environmental, legal and income taxes, when itis management's assessment that a loss is probable and the amountof the loss can be reasonably estimated. Revisions to contingentliabilities are reflected in operations in the period in whichdifferent facts or information become known or circumstances changethat affect the previous assumptions with respect to the likelihood oramount of loss. Reserves for contingent liabilities are based uponmanagement's assumptions and estimates, and advice of legalcounsel or other third parties regarding the probable outcomes of anymatters. Should the outcomes differ from the assumptions and estimates,revisions to the estimated reserves for contingent liabilities would berequired.

Accrued Pension and Postretirement Expense

Pension and postretirement costs are accrued throughout the yearbased on results of an annual study performed by external actuaries. Inaddition to the benefits granted to employees, the timing of the costof these plans is impacted by assumptions used by the actuaries,including assumptions provided by MEHC for the discount rate andlong-term rate of return on assets. Both of these factors requireestimates and projections by management and can fluctuate from periodto period. Actual returns on assets are significantly affected by stockand bond markets, over which management has little control. Theinterest rate at which projected benefits are discounted significantlyaffects amounts expensed.

Revenue Recognition

Revenueis recorded based upon services rendered and electricity, gas and steamdelivered, distributed or supplied to the end of the period. TheCompany records unbilled revenue representing the estimated amountscustomers will be billed for services rendered between the meterreading dates in a particular month and the end of that month. Theunbilled revenue estimate is reversed in the following month.

Where there is an over recovery of United Kingdom distributionbusiness revenue against the maximum regulated amount, revenue isdeferred in an amount equivalent to the over recovered amount. Thedeferred amount is deducted from revenue and included in otherliabilities. Where there is an under recovery, no anticipation of anypotential future recovery is made.

Revenue from thetransportation and storage of gas are recognized based on contractualterms and the related volumes. Kern River and Northern Natural Gas aresubject to the FERC's regulations and, accordingly, certainrevenue collected may be subject to possible refunds upon final ordersin pending rate cases. Kern River and Northern Natural Gas record raterefund liabilities considering their regulatory proceedings and otherthird party regulatory proceedings, advice of counsel and estimatedtotal exposure, as discounted and risk weighted, as well as collectionand other risks.

53

----

Revenue from water delivery is recordedon the basis of the contractual minimum guaranteed water deliverythreshold for the respective contract year. If and when cumulativedeliveries within a contract year exceed the minimum threshold,additional revenue is recognized. Revenue from long-term electricitycontracts is recorded at the lower of the amount billed or the averageof the contract, subject to contractual provisions at each project.

Commission revenue from real estate brokerage transactions andrelated amounts due to agents are recognized when title has transferredfrom seller to buyer. Title fee revenue from real estate transactionsand related amounts due to the title insurer are recognized at theclosing, which is when consideration is received. Fees related to loanoriginations are recognized at the closing, which is when services havebeen provided and consideration is received.

To the extent theestimated amount differs from the actual amount, revenue will beaffected.

Item 7A.    Quantitative and QualitativeDisclosures about Market Risk.

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

Interest Rate Risk

At December31, 2003, the Company had fixed-rate long-term debt of $11,369.4million in aggregate principal amount and having a fair value of$12,015.1 million. These instruments are fixed-rate and therefore donot expose the Company to the risk of earnings loss due to changes inmarket interest rates. However, the fair value of these instrumentswould decrease by approximately $387.3 million if interest rates wereto increase by 10% from their levels at December 31, 2003. Ingeneral, such a decrease in fair value would impact earnings and cashflows only if the Company were to reacquire all or a portion of theseinstruments prior to their maturity.

At December 31, 2002, theCompany had fixed-rate long-term debt and Company-obligated mandatorilyredeemable preferred securities of subsidiary trusts of $11,683.2million in aggregate principal amount and having a fair value of$12,188.8 million. These instruments were fixed-rate and therefore didnot expose the Company to the risk of earnings loss due to changes inmarket interest rates.

At December 31, 2003, the Company hadfloating-rate obligations of $459.8 million that expose the Company tothe risk of increased interest expense in the event of increases inshort-term interest rates. These obligations are not hedged. If thefloating rates were to increase by 1% the Company'sconsolidated interest expense for unhedged floating-rate obligationswould increase by approximately $0.4 million each month in which suchincrease continued based upon December 31, 2003 principal balances.

At December 31, 2002, the Company had floating-rate obligations of$425.1 million that expose the Company to the risk of increasedinterest expense in the event of increases in short-term interestrates. These obligations were not hedged.

Currency ExchangeRate Risk

CE Electric UK entered into certain currency rate swapagreements for its Senior Notes with two large multi-national financialinstitutions. The swap agreements effectively convert the U.S. dollarfixed interest rate to a fixed rate in Sterling. For the $117.1million of 6.853% Senior Notes, the agreements extend untilmaturity on December  30, 2004 and convert the U.S. dollarinterest rate to a fixed Sterling rate of 7.744%. For the$236.2  million of 6.995% Senior Notes, the agreementsextend until maturity on December  30, 2007 and convert the U.S.dollar interest rate to a fixed Sterling rate of 7.737%. Theestimated fair value of these swap agreements at December  31,2003 is approximately $16.0  million based on quotes from thecounterparty to these instruments and represents the estimated amountthat the Company would expect to pay if these agreements wereterminated.

54

----

Yorkshire entered into certain currencyrate swap agreements for its Yankee Bonds with three largemulti-national financial institutions. The swap agreements effectivelyconvert the U.S. dollar fixed interest rate to a fixed rate inSterling. For the $281.1  million of 6.496% Yankee Bonds,the agreements extend until February  25, 2008 and convert theU.S. dollar interest rate to a fixed Sterling rate ranging from7.3175% to 7.345%. The estimated fair value of these swapagreements at December  31, 2003 is approximately $62.6million based on quotes from the counterparties to these instrumentsand represents the estimated amount that the Company would expect topay if these agreements were terminated.

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

Derivatives

MidAmerican Energy enters into variousfinancial derivative instruments, including futures, over-the-counterswaps and forward physical contracts. Senior management provides theoverall direction, structure, conduct and control of MidAmericanEnergy's risk management activities, including authorization andcommunication of risk management policies and procedures, the use offinancial derivative instruments, strategic hedging program guidelines,appropriate market and credit risk limits, and appropriate systems forrecording, monitoring and reporting the results of transactional andrisk management activities.

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

|                                      |  |                  |         |                    |  |        |         |         |  |        |         |         |  |  |
|--------------------------------------|--|------------------|---------|--------------------|--|--------|---------|---------|--|--------|---------|---------|--|--|
| ContractType                         |  | Maturity in 2004 |         | Maturity in2005-07 |  | Total  |
| Non-trading:                         |  |             |    |               |  |   |    |    |  |   |    |    |
| Regulatedelectricassets              |  | $                | 5,924   |               |  | $      | 217     |    |  | $      | 6,141   |    |
| Regulatedelectric(liabilities)       |  |             | (14,275 | )             |  |   | — |    |  |   | (14,275 | )  |
| Regulatedgasassets                   |  |             | 9,008   |               |  |   | — |    |  |   | 9,008   |    |
| Regulatedweather(liabilities)        |  |             | (1,775  | )             |  |   | — |    |  |   | (1,775  | )  |
| Nonregulatedelectricassets           |  |             | 2,953   |               |  |   | 1,676   |    |  |   | 4,629   |    |
| Nonregulatedelectric(liabilities)    |  |             | (1,711  | )             |  |   | (1,131  | )  |  |   | (2,842  | )  |
| Nonregulatedgasassets                |  |             | 11,498  |               |  |   | 798     |    |  |   | 12,296  |    |
| Nonregulatedgas(liabilities)         |  |             | (11,867 | )             |  |   | (739    | )  |  |   | (12,606 | )  |
| Total                                |  |             | (245    | )             |  |   | 821     |    |  |   | 576     |    |
|                                 |  |             |    |               |  |   |    |    |  |   |    |    |
| Trading:                             |  |             |    |               |  |   |    |    |  |   |    |    |
| Nonregulatedgasassets                |  |             | 389     |               |  |   | 247     |    |  |   | 636     |    |
| Nonregulatedgas(liabilities)         |  |             | (419    | )             |  |   | — |    |  |   | (419    | )  |
| Total                                |  |             | (30     | )             |  |   | 247     |    |  |   | 217     |    |
|                                 |  |             |    |               |  |   |    |    |  |   |    |    |
| TotalMidAmerican Energyassets        |  | $                | 29,772  |               |  | $      | 2,938   |    |  | $      | 32,710  |    |
| TotalMidAmerican Energy(liabilities) |  | $                | (30,047 | )             |  | $      | (1,870  | )  |  | $      | (31,917 | )  |
|                                      |

55

----

Item 8.    Financial Statements andSupplementary Data.

|                                                                                                     |  |        |    |        |  |  |
|-----------------------------------------------------------------------------------------------------|--|--------|----|--------|--|--|
| IndependentAuditors' Report                                                                         |  |   | 57 |   |
| ConsolidatedBalance Sheets as of December 31, 2003 and 2002                                         |  |   | 58 |   |
| Consolidated Statements of Operations for the Years EndedDecember 31, 2003, 2002 and 2001           |  |   | 59 |   |
| Consolidated Statements of Stockholders' Equity for theYears Ended December 31, 2003, 2002 and 2001 |  |   | 60 |   |
| Consolidated Statements of Cash Flows for the Years EndedDecember 31, 2003, 2002 and2001            |  |   | 61 |   |
| Notes to Consolidated FinancialStatements                                                           |  |   | 62 |   |
|                                                                                                     |

56

----

INDEPENDENTAUDITORS' REPORT

Board of Directors andStockholdersMidAmerican Energy Holdings CompanyDes Moines,Iowa

We have audited the accompanying consolidated balancesheets 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 yearsin the period ended December 31, 2003. Our audits also included theconsolidated financial statement schedules listed in the Index at Item15. These financial statements and financial statement schedules arethe responsibility of the Company's management. Ourresponsibility is to express an opinion on the financial statements andfinancial statement schedules based on our audits.

We conductedour audits in accordance with auditing standards generally accepted inthe United States of America. Those standards require that we plan andperform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement. An auditincludes examining, on a test basis, evidence supporting the amountsand disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates madeby management, as well as evaluating the overall financial statementpresentation. We believe that our audits provide a reasonable basis forour opinion.

In our opinion, such consolidated financialstatements present fairly, in all material respects, the financialposition of MidAmerican Energy Holdings Company and subsidiaries as ofDecember 31, 2003 and 2002, and the results of their operations andtheir cash flows for each of the three years in the period endedDecember 31, 2003, in conformity with accounting principles generallyaccepted in the United States of America. Also, in our opinion, suchconsolidated financial statement schedules, when considered in relationto the basic consolidated financial statements taken as a whole,present fairly in all material respects the information set forththerein.

As discussed in Note 2 to the consolidated financialstatements, the Company changed its accounting policy for assetretirement obligations and for variable interest entities in 2003, forgoodwill and other intangible assets in 2002, and for majormaintenance, overhaul and well workover costs in 2001.

/s/ Deloitte & Touche LLP

DELOITTE & TOUCHE LLPDes Moines,IowaFebruary 9, 2004(March 1, 2004 as to Notes 2, 5 and20)

57

----

MIDAMERICAN ENERGY HOLDINGSCOMPANYCONSOLIDATED BALANCE SHEETS(Amounts inthousands)

|                                                                                                                                              |  |                   |            |         |  |        |            |         |  |  |
|----------------------------------------------------------------------------------------------------------------------------------------------|--|-------------------|------------|---------|--|--------|------------|---------|--|--|
|                                                                                                                                         |  | Asof December 31, |
|                                                                                                                                         |  | 2003              |            | 2002    |
| **ASSETS**                                                                                                                                   |
| Currentassets:                                                                                                                               |  |              |       |    |  |   |       |    |
| Cash and cashequivalents                                                                                                                     |  | $                 | 660,213    |    |  | $      | 844,430    |    |
| Restrictedcash and short-terminvestments                                                                                                     |  |              | 55,281     |    |  |   | 50,808     |    |
| Accountsreceivable, net of allowance for doubtful accounts of $26,004 and$39,742                                                             |  |              | 666,063    |    |  |   | 707,731    |    |
| Inventories                                                                                                                                  |  |              | 123,301    |    |  |   | 126,938    |    |
| Othercurrentassets                                                                                                                           |  |              | 371,855    |    |  |   | 246,731    |    |
| Totalcurrentassets                                                                                                                           |  |              | 1,876,713  |    |  |   | 1,976,638  |    |
| Properties,plants and equipment,net                                                                                                          |  |              | 11,180,979 |    |  |   | 10,284,487 |    |
| Goodwill                                                                                                                                     |  |              | 4,305,643  |    |  |   | 4,258,132  |    |
| Regulatoryassets                                                                                                                             |  |              | 512,549    |    |  |   | 415,804    |    |
| Otherinvestments                                                                                                                             |  |              | 228,896    |    |  |   | 446,732    |    |
| Equityinvestments                                                                                                                            |  |              | 234,370    |    |  |   | 273,707    |    |
| Deferredcharges and otherassets                                                                                                              |  |              | 829,039    |    |  |   | 779,420    |    |
| **Totalassets**                                                                                                                              |  | $                 | 19,168,189 |    |  | $      | 18,434,920 |    |
| **LIABILITIESAND STOCKHOLDERS' EQUITY**                                                                                                      |
| Currentliabilities:                                                                                                                          |  |              |       |    |  |   |       |    |
| Accountspayable                                                                                                                              |  | $                 | 345,237    |    |  | $      | 462,960    |    |
| Accruedinterest                                                                                                                              |  |              | 189,635    |    |  |   | 192,015    |    |
| Accruedtaxes                                                                                                                                 |  |              | 112,823    |    |  |   | 108,940    |    |
| Otheraccruedliabilities                                                                                                                      |  |              | 443,531    |    |  |   | 457,058    |    |
| Short-termdebt                                                                                                                               |  |              | 48,036     |    |  |   | 79,782     |    |
| Currentportion of long-termdebt                                                                                                              |  |              | 500,941    |    |  |   | 470,213    |    |
| Currentportion of parent company subordinateddebt                                                                                            |  |              | 100,000    |    |  |   | —    |    |
| Totalcurrentliabilities                                                                                                                      |  |              | 1,740,203  |    |  |   | 1,770,968  |    |
| Otherlong-term accruedliabilities                                                                                                            |  |              | 1,827,633  |    |  |   | 1,486,608  |    |
| Parentcompany seniordebt                                                                                                                     |  |              | 2,777,878  |    |  |   | 2,323,387  |    |
| Parentcompany subordinateddebt                                                                                                               |  |              | 1,772,146  |    |  |   | —    |    |
| Subsidiaryand projectdebt                                                                                                                    |  |              | 6,674,640  |    |  |   | 7,077,087  |    |
| Deferredincometaxes                                                                                                                          |  |              | 1,433,144  |    |  |   | 1,238,421  |    |
| Totalliabilities                                                                                                                             |  |              | 16,225,644 |    |  |   | 13,896,471 |    |
| Deferredincome                                                                                                                               |  |              | 69,201     |    |  |   | 80,078     |    |
| Minorityinterest                                                                                                                             |  |              | 9,754      |    |  |   | 7,351      |    |
| Preferredsecurities ofsubsidiaries                                                                                                           |  |              | 92,145     |    |  |   | 93,325     |    |
| Company-obligatedmandatorily redeemable preferred securities of subsidiarytrusts                                                             |  |              | —    |    |  |   | 2,063,412  |    |
| Commitmentsand contingencies (Note19)                                                                                                        |  |              |       |    |  |   |       |    |
| Stockholders'equity:                                                                                                                         |  |              |       |    |  |   |       |    |
| Zero couponconvertible preferred stock — authorized 50,000 shares, no parvalue; 41,263 shares outstanding at December 31, 2003 and2002 |  |              | —    |    |  |   | —    |    |
| Commonstock — authorized 60,000 shares, no par value; 9,281 sharesissued and outstanding at December 31, 2003 and2002                  |  |              | —    |    |  |   | —    |    |
| Additionalpaid-incapital                                                                                                                     |  |              | 1,957,277  |    |  |   | 1,956,509  |    |
| Retainedearnings                                                                                                                             |  |              | 999,627    |    |  |   | 584,009    |    |
| Accumulatedother comprehensive loss,net                                                                                                      |  |              | (185,459   | )  |  |   | (246,235   | )  |
| Totalstockholders'equity                                                                                                                     |  |              | 2,771,445  |    |  |   | 2,294,283  |    |
| **Totalliabilities and stockholders'equity**                                                                                                 |  | $                 | 19,168,189 |    |  | $      | 18,434,920 |    |
|                                                                                                                                              |

Theaccompanying notes are an integral part of these financialstatements.

58

----

MIDAMERICAN ENERGY HOLDINGS COMPANYCONSOLIDATED STATEMENTS OF OPERATIONS(Amounts inthousands)

|                                                                        |  |                        |           |         |  |        |           |         |  |        |           |         |  |  |
|------------------------------------------------------------------------|--|------------------------|-----------|---------|--|--------|-----------|---------|--|--------|-----------|---------|--|--|
|                                                                   |  | YearEnded December 31, |
|                                                                   |  | 2003                   |           | 2002    |  | 2001   |
| **Revenue:**                                                           |  |                   |      |    |  |   |      |    |  |   |      |    |
| Operatingrevenue                                                       |  | $                      | 5,948,224 |    |  | $      | 4,794,010 |    |  | $      | 4,696,781 |    |
| Incomeon equityinvestments                                             |  |                   | 38,224    |    |  |   | 40,520    |    |  |   | 39,565    |    |
| Interestand dividendincome                                             |  |                   | 47,911    |    |  |   | 56,250    |    |  |   | 24,552    |    |
| Otherincome                                                            |  |                   | 110,318   |    |  |   | 77,359    |    |  |   | 212,082   |    |
| Totalrevenue                                                           |  |                   | 6,144,677 |    |  |   | 4,968,139 |    |  |   | 4,972,980 |    |
| **Costsandexpenses:**                                                  |  |                   |      |    |  |   |      |    |  |   |      |    |
| Costofsales                                                            |  |                   | 2,416,132 |    |  |   | 1,844,024 |    |  |   | 2,341,178 |    |
| Operatingexpense                                                       |  |                   | 1,527,516 |    |  |   | 1,345,205 |    |  |   | 1,176,422 |    |
| Depreciationandamortization                                            |  |                   | 609,889   |    |  |   | 525,902   |    |  |   | 538,702   |    |
| Interestexpense                                                        |  |                   | 771,831   |    |  |   | 647,379   |    |  |   | 499,263   |    |
| Lessinterestcapitalized                                                |  |                   | (30,483   | )  |  |   | (37,469   | )  |  |   | (86,469   | )  |
| Totalcosts andexpenses                                                 |  |                   | 5,294,885 |    |  |   | 4,325,041 |    |  |   | 4,469,096 |    |
| **Incomebefore provision for incometaxes**                             |  |                   | 849,792   |    |  |   | 643,098   |    |  |   | 503,884   |    |
| Provisionfor incometaxes                                               |  |                   | 250,971   |    |  |   | 99,588    |    |  |   | 250,064   |    |
| **Incomebefore minority interest and preferreddividends**              |  |                   | 598,821   |    |  |   | 543,510   |    |  |   | 253,820   |    |
| Minorityinterest and preferreddividends                                |  |                   | 183,203   |    |  |   | 163,467   |    |  |   | 106,547   |    |
| **Incomebefore cumulative effect of change in accountingprinciple**    |  |                   | 415,618   |    |  |   | 380,043   |    |  |   | 147,273   |    |
| Cumulativeeffect of change in accounting principle, net of tax (Note2) |  |                   | —   |    |  |   | —   |    |  |   | (4,604    | )  |
| **Netincome available to common and preferredstockholders**            |  | $                      | 415,618   |    |  | $      | 380,043   |    |  | $      | 142,669   |    |
|                                                                        |

Theaccompanying notes are an integral part of these financialstatements.

59

----

MIDAMERICAN ENERGY HOLDINGS COMPANYCONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY(Amountsin thousands)

|                                                                   |  |                         |         |             |  |                          |         |                  |  |                                           |           |        |  |        |         |         |  |        |          |         |  |        |           |         |  |  |
|-------------------------------------------------------------------|--|-------------------------|---------|-------------|--|--------------------------|---------|------------------|--|-------------------------------------------|-----------|--------|--|--------|---------|---------|--|--------|----------|---------|--|--------|-----------|---------|--|--|
|                                                              |  | OutstandingCommonShares |         | CommonStock |  | AdditionalPaid-inCapital |         | RetainedEarnings |  | AccumulatedOtherComprehensiveIncome(Loss) |           | Total  |
| **Balance, January 1,2001**                                       |  |                    | 9,281   |        |  | $                        | — |             |  | $                                         | 1,553,073 |   |  | $      | 81,257  |    |  | $      | (57,929  | )  |  | $      | 1,576,401 |    |
| Netincome                                                         |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | 142,669 |    |  |   | —  |    |  |   | 142,669   |    |
| Othercomprehensive income: Foreign currency translationadjustment |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | (22,103  | )  |  |   | (22,103   | )  |
| Fairvalue adjustment on cash flow hedges, net of tax of$8,143     |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | 18,490   |    |  |   | 18,490    |    |
| Minimumpension liability adjustment, net of tax of$(3,448)        |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | (4,847   | )  |  |   | (4,847    | )  |
| Unrealizedlosses on securities, net of tax of$(1,315)             |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | (2,443   | )  |  |   | (2,443    | )  |
| Totalother comprehensiveincome                                    |  |                    |    |        |  |                     |    |             |  |                                      |      |   |  |   |    |    |  |   |     |    |  |   | 131,766   |    |
| **Balance,December 31,2001**                                      |  |                    | 9,281   |        |  |                     | — |             |  |                                      | 1,553,073 |   |  |   | 223,926 |    |  |   | (68,832  | )  |  |   | 1,708,167 |    |
| Netincome                                                         |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | 380,043 |    |  |   | —  |    |  |   | 380,043   |    |
| Othercomprehensive income:                                        |  |
| Foreign currencytranslationadjustment                             |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | 166,880  |    |  |   | 166,880   |    |
| Fairvalue adjustment on cash flow hedges, net of tax of$(10,106)  |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | (27,623  | )  |  |   | (27,623   | )  |
| Minimumpension liability adjustment, net of tax of$(135,707)      |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | (313,456 | )  |  |   | (313,456  | )  |
| Unrealizedlosses on securities, net of tax of$(1,813)             |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | (3,204   | )  |  |   | (3,204    | )  |
| Totalother comprehensiveincome                                    |  |                    |    |        |  |                     |    |             |  |                                      |      |   |  |   |    |    |  |   |     |    |  |   | 202,640   |    |
| Issuanceof zero-coupon convertible preferredstock                 |  |                    | — |        |  |                     | — |             |  |                                      | 402,000   |   |  |   | — |    |  |   | —  |    |  |   | 402,000   |    |  |
| Retirementof stockoptions                                         |  |                    | — |        |  |                     | — |             |  |                                      | 815       |   |  |   | (19,960 | )  |  |   | —  |    |  |   | (19,145   | )  |  |
| Otherequitytransactions                                           |  |                    | — |        |  |                     | — |             |  |                                      | 621       |   |  |   | — |    |  |   | —  |    |  |   | 621       |    |
| **Balance,December 31,2002**                                      |  |                    | 9,281   |        |  |                     | — |             |  |                                      | 1,956,509 |   |  |   | 584,009 |    |  |   | (246,235 | )  |  |   | 2,294,283 |    |
| Netincome                                                         |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | 415,618 |    |  |   | —  |    |  |   | 415,618   |    |  |
| Othercomprehensive income:                                        |  |
| Foreign currencytranslationadjustment                             |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | 58,148   |    |  |   | 58,148    |    |
| Fairvalue adjustment on cash flow hedges, net of tax of$7,202     |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | 16,769   |    |  |   | 16,769    |    |
| Minimumpension liability adjustment, net of tax of$(6,425)        |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | (14,989  | )  |  |   | (14,989   | )  |
| Unrealizedlosses on securities, net of tax of$566                 |  |                    | — |        |  |                     | — |             |  |                                      | —   |   |  |   | — |    |  |   | 848      |    |  |   | 848       |    |
| Totalother comprehensiveincome                                    |  |                    |    |        |  |                     |    |             |  |                                      |      |   |  |   |    |    |  |   |     |    |  |   | 476,394   |    |  |
| Otherequitytransactions                                           |  |                    | — |        |  |                     | — |             |  |                                      | 768       |   |  |   | — |    |  |   | —  |    |  |   | 768       |    |
| **Balance,December 31, 2003**                                     |  |                    | 9,281   |        |  | $                        | — |             |  | $                                         | 1,957,277 |   |  | $      | 999,627 |    |  | $      | (185,459 | )  |  | $      | 2,771,445 |    |
|                                                                   |

Theaccompanying notes are an integral part of these financialstatements.

60

----

MIDAMERICAN ENERGY HOLDINGS COMPANYCONSOLIDATED STATEMENTS OF CASH FLOWS(Amounts inthousands)

|                                                                               |  |                        |            |         |  |        |            |         |  |        |          |         |  |  |
|-------------------------------------------------------------------------------|--|------------------------|------------|---------|--|--------|------------|---------|--|--------|----------|---------|--|--|
|                                                                          |  | YearEnded December 31, |
|                                                                          |  | 2003                   |            | 2002    |  | 2001   |
| Cashflows from operating activities:                                          |  |
| Netincome                                                                     |  | $                      | 415,618    |    |  | $      | 380,043    |    |  | $      | 142,669  |    |
| Adjustmentsto reconcile net cash flows from operatingactivities:              |  |
| Distributions less income onequityinvestments                                 |  |                   | 40,160     |    |  |   | (11,383    | )  |  |   | (28,515  | )  |
| Gainson assetsales                                                            |  |                   | (24,321    | )  |  |   | (25,329    | )  |  |   | (179,493 | )  |
| Depreciationandamortization                                                   |  |                   | 609,889    |    |  |   | 525,902    |    |  |   | 442,284  |    |
| Amortizationofgoodwill                                                        |  |                   | —    |    |  |   | —    |    |  |   | 96,418   |    |
| Amortizationof regulatory assets and liabilities andother                     |  |                   | (14,363    | )  |  |   | 8,709      |    |  |   | 23,774   |    |
| Amortizationof deferred financingcosts                                        |  |                   | 28,046     |    |  |   | 28,615     |    |  |   | 20,737   |    |
| Provisionfor deferred incometaxes                                             |  |                   | 237,322    |    |  |   | (16,228    | )  |  |   | 152,920  |    |
| Cumulativeeffect of change in accounting principle, net oftax                 |  |                   | —    |    |  |   | —    |    |  |   | 4,604    |    |
| Changesin otheritems:                                                         |  |                   |       |    |  |   |       |    |  |   |     |    |
| Accountsreceivable and other currentassets                                    |  |                   | (27,447    | )  |  |   | (201,147   | )  |  |   | 571,910  |    |
| Accountspayable and other accruedliabilities                                  |  |                   | (46,138    | )  |  |   | 64,759     |    |  |   | (420,434 | )  |
| Deferredincome                                                                |  |                   | (9,344     | )  |  |   | (4,839     | )  |  |   | 6,428    |    |
| Other                                                                         |  |                   | 8,501      |    |  |   | 8,624      |    |  |   | 13,696   |    |
| Netcash flows from operatingactivities                                        |  |                   | 1,217,923  |    |  |   | 757,726    |    |  |   | 846,998  |    |
| Cashflows from investingactivities:                                           |  |
| Acquisitions, net of cashacquired                                             |  |                   | (54,263    | )  |  |   | (1,416,937 | )  |  |   | (81,934  | )  |
| Sale(purchase) of convertible preferredsecurities                             |  |                   | 288,750    |    |  |   | (275,000   | )  |  |   | —  |    |
| Capitalexpenditures relating to operatingprojects                             |  |                   | (677,256   | )  |  |   | (542,615   | )  |  |   | (398,165 | )  |
| Constructionand other developmentcosts                                        |  |                   | (513,771   | )  |  |   | (965,470   | )  |  |   | (178,587 | )  |
| Purchaseof affiliatesnotes                                                    |  |                   | (35,029    | )  |  |   | —    |    |  |   | (13,247  | )  |
| Proceedsfrom sale ofassets                                                    |  |                   | 13,113     |    |  |   | 214,070    |    |  |   | 377,396  |    |
| Decreasein restricted cash andinvestments                                     |  |                   | 7,415      |    |  |   | 16,351     |    |  |   | 24,540   |    |
| Other                                                                         |  |                   | (32,126    | )  |  |   | 61,790     |    |  |   | 31,453   |    |
| Netcash flows from investingactivities                                        |  |                   | (1,003,167 | )  |  |   | (2,907,811 | )  |  |   | (238,544 | )  |
| Cashflows from financing activities:                                          |  |
| Proceedsfrom subsidiary and projectdebt                                       |  |                   | 1,157,649  |    |  |   | 1,485,349  |    |  |   | 200,000  |    |
| Proceedsfrom parent company seniordebt                                        |  |                   | 449,295    |    |  |   | 700,000    |    |  |   | —  |    |
| Repaymentsof subsidiary and projectdebt                                       |  |                   | (1,490,986 | )  |  |   | (395,370   | )  |  |   | (437,372 | )  |
| Repaymentof parent company seniordebt                                         |  |                   | (215,000   | )  |  |   | —    |    |  |   | —  |    |
| Repaymentof parent company subordinateddebt                                   |  |                   | (198,958   | )  |  |   | —    |    |  |   | —  |    |
| Netproceeds from (repayment of) parent company revolving creditfacility       |  |                   | —    |    |  |   | (153,500   | )  |  |   | 68,500   |    |
| Repaymentof otherobligations                                                  |  |                   | —    |    |  |   | (94,297    | )  |  |   | —  |    |
| Netrepayment of subsidiary short-termdebt                                     |  |                   | (31,750    | )  |  |   | (472,835   | )  |  |   | (74,144  | )  |
| Proceedsfrom issuance of trust preferredsecurities                            |  |                   | —    |    |  |   | 1,273,000  |    |  |   | —  |    |
| Proceedsfrom issuance of preferredstock                                       |  |                   | —    |    |  |   | 402,000    |    |  |   | —  |    |
| Redemptionof preferred securities ofsubsidiaries                              |  |                   | (1,176     | )  |  |   | (127,908   | )  |  |   | (24,910  | )  |
| Other                                                                         |  |                   | (95,411    | )  |  |   | (61,205    | )  |  |   | 9,459    |    |
| Netcash flows from financingactivities                                        |  |                   | (426,337   | )  |  |   | 2,555,234  |    |  |   | (258,467 | )  |
| Effectof exchange ratechanges                                                 |  |                   | 27,364     |    |  |   | 52,536     |    |  |   | (1,394   | )  |
| **Netchange in cash and cashequivalents**                                     |  |                   | (184,217   | )  |  |   | 457,685    |    |  |   | 348,593  |    |
| **Cashand cash equivalents at beginning ofperiod**                            |  |                   | 844,430    |    |  |   | 386,745    |    |  |   | 38,152   |    |
| **Cashand cash equivalents at end ofperiod**                                  |  | $                      | 660,213    |    |  | $      | 844,430    |    |  | $      | 386,745  |    |
| SupplementalDisclosure:                                                       |  |                   |       |    |  |   |       |    |  |   |     |    |
| Interestpaid, net of interestcapitalized                                      |  | $                      | 706,039    |    |  | $      | 588,972    |    |  | $      | 389,953  |    |
| Incometaxespaid                                                               |  | $                      | 9,911      |    |  | $      | 101,225    |    |  | $      | 133,139  |    |
| Non-cashtransaction – ROP note received under NIA ArbitrationSettlement |  | $                      | 97,000     |    |  | $      | —    |    |  | $      | —  |    |
|                                                                               |

The accompanyingnotes are an integral part of these financialstatements.

61

----

MIDAMERICAN ENERGYHOLDINGS COMPANYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Organization and Operations

MidAmericanEnergy Holdings Company ("MEHC") and itssubsidiaries (together with MEHC, the"Company") is a United States-based privatelyowned global energy company. The Company's operations areorganized and managed on seven distinct platforms: MidAmerican EnergyCompany ("MidAmerican Energy"), Kern RiverGas Transmission Company ("Kern River"),Northern Natural Gas Company ("Northern NaturalGas"), CE Electric UK Funding ("CE ElectricUK") (which includes Northern Electric plc("Northern Electric ") and YorkshireElectricity Group plc ("Yorkshire ")),CalEnergy Generation-Domestic (interests in independent power projectsand related operations), CalEnergy Generation-Foreign (the subsidiariesowning the Upper Mahiao, Malitbog and Mahanagdong Projects(collectively the "Leyte Projects") and theCasecnan project) and HomeServices of America, Inc. (collectively withits subsidiaries, "HomeServices"). Throughthese platforms, the Company owns and operates a combined electric andnatural gas utility company in the United States, two natural gaspipeline companies in the United States, two electricity distributioncompanies in the United Kingdom, a diversified portfolio of domesticand international independent power projects and the second largestresidential real estate brokerage firm in the United States.

On March 14, 2000, MEHC and an investor group comprised ofBerkshire Hathaway Inc. ("BerkshireHathaway"), Walter Scott, Jr., a director of MEHC, DavidL. Sokol, Chairman and Chief Executive Officer of MEHC, and Gregory E.Abel, President and Chief Operating Officer of MEHC, closed on adefinitive agreement and plan of merger whereby the investor group,together with certain of Mr. Scott's family members and familytrusts and corporations, acquired all of the outstanding common stockof MEHC (the "Teton Transaction").

MEHC initially incorporated in 1971 under the laws of theState of Delaware and was reincorporated in 1999 in Iowa, at which timeit changed its name from CalEnergy Company, Inc. to MidAmerican EnergyHoldings Company.

In these notes to consolidatedfinancial statements, references to "U.S.dollars," "dollars,""$" or "cents" areto the currency of the United States, references to"pounds sterling,""£,""sterling," "pence"or "p" are to the currency of the UnitedKingdom and references to "pesos" are to thecurrency of the Philippines. References to kW means kilowatts, MW meansmegawatts, GW means gigawatts, kWh means kilowatt hours, MWh meansmegawatt hours, GWh means gigawatts hours, kV means kilovolts, mmcfmeans million cubic feet, Bcf means billion cubic feet, Tcf meanstrillion cubic feet, MMBtus means million British thermal units and Dthmeans decatherms or MMBtus.

2.    Summary of SignificantAccounting Policies

Principles of Consolidation

The consolidated financial statements include the accountsof MEHC and its wholly owned subsidiaries excluding entities for whichadoption of FASB Interpretation No. 46R, "Consolidation ofVariable Interest Entities" ("FIN46R") was required at December 31, 2003. Subsidiarieswhich are less than 100% owned but greater than 50% ownedare consolidated with a minority interest. Subsidiaries that are50% owned or less, but where the Company has the ability toexercise significant influence, are accounted for under the equitymethod of accounting. Investments where the Company's ability toinfluence is limited are accounted for under the cost method ofaccounting. All inter-enterprise transactions and accounts have beeneliminated. The results of operations of the Company include theCompany's proportionate share of results of operations ofentities acquired from the date of each acquisition for purchasebusiness combinations.

For the Company's foreignoperations whose functional currency is not the U.S. dollar, the assetsand liabilities are translated into U.S. dollars at current exchangerates. Resulting translation adjustments are reflected as accumulatedother comprehensive income (loss) in stockholders' equity.Revenue and expenses are translated at average exchange rates for theperiod. Transaction gains and losses that arise from exchange ratefluctuations on transactions denominated in a currency other than thefunctional currency are included in the results of operations asincurred.

62

----

Reclassifications

Certain amountsin the fiscal 2002 and 2001 consolidated financial statements andsupporting note disclosures have been reclassified to conform to thefiscal 2003 presentation. Such reclassification did not impactpreviously reported net income or retained earnings.

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

Use of Estimates

The preparation ofconsolidated financial statements in conformity with accountingprinciples generally accepted in the United States requires managementto make estimates and assumptions that affect the reported amounts ofassets and liabilities and disclosure of contingent assets andliabilities at the date of the consolidated financial statements andthe reported amounts of revenue and expenses during the reportingperiod. Actual results could differ from those estimates.

Accounting for the Effects of Certain Types of Regulation

MidAmerican Energy, Kern River and Northern Natural Gas preparetheir financial statements in accordance with the provisions ofStatement of Financial Accounting Standards("SFAS") No. 71 ("SFAS71"), which differs in certain respects from theapplication of generally accepted accounting principles bynon-regulated businesses. In general, SFAS 71 recognizes thataccounting for rate-regulated enterprises should reflect the economiceffects of regulation. As a result, a regulated utility is required todefer the recognition of costs (a regulatory asset) or the recognitionof obligations (a regulatory liability) if it is probable that, throughthe rate-making process, there will be a corresponding increase ordecrease in future rates. Accordingly, MidAmerican Energy, Kern Riverand Northern Natural Gas have deferred certain costs, which will beamortized over various future periods. To the extent that collection ofsuch costs or payment of such obligations is no longer probable as aresult of changes in regulation, the associated regulatory asset orliability is charged or credited to income.

A possibleconsequence of deregulation of the regulated energy industry is thatSFAS 71 may no longer apply. If portions of the Company'sregulated energy operations no longer meet the criteria of SFAS 71, theCompany could be required to write off the related regulatory assetsand liabilities from its balance sheet, and thus a material adjustmentto earnings in that period could result if regulatory assets orliabilities are not recovered in transition provisions of anyderegulation legislation.

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

Cash and Cash Equivalents

The Company considers allinvestment instruments purchased with an original maturity of threemonths or less to be cash equivalents. Investments other thanrestricted cash are primarily commercial paper and money marketsecurities. Restricted cash is not considered a cash equivalent.

Restricted Cash and Investments

The current restricted cashand short-term investments balance recorded separately in restrictedcash and short term investments and in deferred charges and otherassets, was $119.5 million and $58.7 million at December 31, 2003 and2002, respectively, and includes commercial paper and money marketsecurities. The balance is mainly composed of amounts deposited inrestricted accounts from which the Company will source its debt servicereserve requirements relating to the projects and customer depositsheld in escrow. The debt service funds are restricted by theirrespective project debt agreements to be used only for the relatedproject.

63

----

The Company's nucleardecommissioning trust funds and other marketable securities areclassified as available for sale and are accounted for at fairvalue.

Allowance for Doubtful Accounts

The allowancefor doubtful accounts is based on the Company's assessment of thecollectibility of payments from its customers. This assessment requiresjudgment regarding the outcome of pending disputes, arbitrations andthe ability of customers to pay the amounts owed to the Company.

Fair Value of Financial Instruments

The fair value of afinancial instrument is the amount at which the instrument could beexchanged in a current transaction between willing parties, other thanin a forced sale or liquidation. Although management uses its bestjudgment 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 necessarilyindicative of the amounts that the Company could realize in a currenttransaction.

The methods and assumptions used to estimate fairvalue are as follows:

Short-term debt — Due to theshort-term nature of the short-term debt, the fair value approximatesthe carrying value.

Debt instruments — The fair value ofall debt instruments has been estimated based upon quoted market pricesas supplied by third-party broker dealers, where available, or at thepresent value of future cash flows discounted at rates consistent withcomparable maturities with similar credit risks. The Company is unableto estimate a fair value for the Leyte debt as there are no quotedmarket prices available.

Other financial instruments — Allother financial instruments of a material nature are short-term and thefair value approximates the carrying amount.

Properties, Plantsand Equipment, Net

Properties, plants and equipment arerecorded at historical cost. The cost of major additions andbetterments are capitalized, while replacements, maintenance, andrepairs that do not improve or extend the lives of the respectiveassets are expensed.

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

Impairment of Long-Lived Assets

The Company'slong-lived assets consist primarily of properties, plants andequipment. Depreciation is computed using the straight-line methodbased on economic lives or regulatorily mandated recovery periods. TheCompany believes the useful lives assigned to the depreciable assets,which generally range from 3 to 87 years, are reasonable.

TheCompany periodically evaluates long-lived assets, including properties,plants and equipment, when events or changes in circumstances indicatethat the carrying value of these assets may not be recoverable. Uponthe occurrence of a triggering event, the carrying amount of along-lived asset is reviewed to assess whether the recoverable amounthas declined below its carrying amount. The recoverable amount is theestimated net future cash flows that the Company expects to recoverfrom the future use of the asset, undiscounted and without interest,plus the asset's residual value on disposal. Where therecoverable amount of the long-lived asset is less than the carryingvalue, an impairment loss would be recognized to write down the assetto its fair value that is based on discounted estimated cash flows fromthe future use of the asset.

Goodwill

On January 1,2002, the Company adopted SFAS No. 142, "Goodwill andOther Intangible Assets" ("SFAS142"), which establishes the accounting for acquiredgoodwill and other intangible assets, and 

64

----

provides that goodwill and indefinite-livedintangible assets will not be amortized, but will be tested forimpairment on an annual basis. The Company's related amortizationconsisted primarily of goodwill amortization. Following is areconciliation of net income available to common and preferredstockholders as originally reported for the years ended December 31,2003, 2002 and 2001 to adjusted net income available to common andpreferred stockholders (in thousands):

|                                                                  |  |                   |         |        |  |        |         |        |  |        |         |         |  |  |
|------------------------------------------------------------------|--|-------------------|---------|--------|--|--------|---------|--------|--|--------|---------|---------|--|--|
|                                                             |  | YearEndedDecember |
|                                                             |  | 2003              |         | 2002   |  | 2001   |
| Reportednet income available to common and preferredstockholders |  | $                 | 415,618 |   |  | $      | 380,043 |   |  | $      | 142,669 |    |
| Amortizationofgoodwill                                           |  |              | — |   |  |   | — |   |  |   | 96,418  |    |
| Taxeffect ofamortization                                         |  |              | — |   |  |   | — |   |  |   | (2,018  | )  |
| Adjustednet income available to common and preferredstockholders |  | $                 | 415,618 |   |  | $      | 380,043 |   |  | $      | 237,069 |    |
|                                                                  |

TheCompany completed its annual review pursuant to SFAS 142 for itsreporting units during the fourth quarter of 2003 primarily using adiscounted cash flow methodology. No impairment was indicated as aresult of these assessments.

Capitalization of Interest andAllowance for Funds Used During Construction

Allowance forfunds used during construction ("AFUDC")represents the approximate net composite interest cost of borrowedfunds and a reasonable return on the equity funds used forconstruction. Although AFUDC increases both utility plant and earnings,it is realized in cash through depreciation provisions included inrates for subsidiaries that apply SFAS 71. Interest and AFUDC forsubsidiaries that apply SFAS 71 are capitalized as a component ofprojects under construction and will be amortized over theassets' estimated useful lives.

Deferred FinancingCost

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

Contingent Liabilities

The Company establishes reserves forestimated loss contingencies, such as environmental, legal and incometaxes, when it is management's assessment that a loss is probableand the amount of the loss can be reasonably estimated.

Deferred Income Taxes

The Company recognizes deferred taxassets and liabilities based on the difference between the financialstatement and tax basis of assets and liabilities using estimated taxrates in effect for the year in which the differences are expected toreverse. The Company does not intend to repatriate earnings of foreignsubsidiaries in the foreseeable future. As a result, deferred UnitedStates income taxes are not provided for currency translationadjustments, retained earnings of international subsidiaries orcorporate joint ventures unless the earnings are intended to beremitted.

Revenue Recognition

Revenue is recorded basedupon services rendered and electricity, gas and steam delivered,distributed or supplied to the end of the period. The Company recordsunbilled revenue representing the estimated amounts customers will bebilled for services rendered between the meter reading dates in aparticular month and the end of that month. The unbilled revenueestimate is reversed in the following month.

Where billingsresult in an overrecovery of United Kingdom distribution businessrevenue against the maximum regulated amount, revenue is deferred in anamount equivalent to the over recovered amount. The deferred amount isdeducted from revenue and included in other accrued liabilities. Wherethere is an under recovery, no anticipation of any potential futurerecovery is made.

65

----

Revenue from the transportation andstorage of gas are recognized based on contractual terms and therelated volumes. Kern River and Northern Natural Gas are subject to theFederal Energy Regulatory Commission's("FERC") regulations and, accordingly,certain revenue collected may be subject to possible refunds upon finalorders in pending rate cases. Kern River and Northern Natural Gasrecord rate refund liabilities, which are included in other accruedliabilities, considering their regulatory proceedings and other thirdparty regulatory proceedings, advice of counsel and estimated totalexposure, as well as collection and other risks.

Revenue fromwater delivery is recorded on the basis of the contractual minimumguaranteed water delivery threshold for the respective contract year.If and when cumulative deliveries within a contract year exceed theminimum threshold, additional revenue is recognized. Revenue fromlong-term electricity contracts is recorded at the lower of the amountbilled or the average of the contract, subject to contractualprovisions at each project.

Commission revenue from real estatebrokerage transactions and related amounts due to agents are recognizedwhen title has transferred from seller to buyer. Title fee revenue fromreal estate transactions and related amounts due to the title insurerare recognized at the closing, which is when consideration is received.Fees related to loan originations are recognized at the closing, whichis when services have been provided and consideration is received.

Financial Instruments

The Company currently utilizes swapagreements and forward purchase agreements to manage market risks andreduce its exposure resulting from fluctuation in interest rates,foreign currency exchange rates and electric and gas prices. Forinterest rate swap agreements, the net cash amounts paid or received onthe agreements are accrued and recognized as an adjustment to interestexpense. Gains and losses related to gas forward contracts are deferredand included in the measurement of the related gas purchases. Theseinstruments are either exchange traded or with counterparties of highcredit quality; therefore, the risk of nonperformance by thecounterparties is considered to be negligible.

AccountingPrinciple Change

Effective January 1, 2001, the Company changedits accounting policy regarding major maintenance and repairs fornon-regulated gas projects, non-regulated plant overhaul costs andgeothermal well rework costs to the direct expense method from theformer policy of accruals based on long-term scheduled maintenanceplans for the gas projects and deferral and amortization of plantoverhaul costs and geothermal well rework costs over the estimateduseful lives. The cumulative effect of the change in accountingprinciple was $4.6 million, net of taxes of $0.7 million.

NewAccounting Pronouncements

On January 1, 2003, the Companyadopted SFAS No. 143, "Accounting for Asset RetirementObligations". This statement provides accounting anddisclosure requirements for retirement obligations associated withlong-lived assets. The cumulative effect of initially applying thisstatement by the Company was immaterial.

The Company identifiedlegal retirement obligations for nuclear decommissioning, wet and dryash landfills and offshore and minor lateral pipeline facilities. OnJanuary 1, 2003, the Company recorded $289.3 million of assetretirement obligation ("ARO") liabilities;$13.9 million of ARO assets, net of accumulated depreciation; $114.6million of regulatory assets; and reclassified $1.0 million ofaccumulated depreciation to the ARO liability. The initial AROliability recognized includes $266.5 million that pertains toobligations associated with the decommissioning of the Quad Citiesnuclear station. The $266.5 million includes a $159.8 million nucleardecommissioning liability that had been recorded at December 31, 2002.The adoption of this statement did not have a material impact on theoperations of the regulated entities, as the effects were offset by theestablishment of regulatory assets, totaling $114.6 million, pursuantto SFAS 71, "Accounting for the Effects of Certain Typesof Regulation".

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

66

----

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

On April 30, 2003, the FASB issued SFAS No.149, "Amendment of Statement 133 on Derivative Instrumentsand Hedging Activities" ("SFAS149"). SFAS 149 amends SFAS No. 133 for derivativeinstruments, including certain derivative instruments embedded in othercontracts and for hedging activities. SFAS 149 requires contracts withcomparable characteristics to be accounted for similarly. Inparticular, SFAS 149 clarifies when a contract with an initial netinvestment meets the characteristic of a derivative and clarifies whena derivative that contains a financing component will require specialreporting in the statement of cash flows. SFAS 149 is effective for theCompany for contracts entered into or modified after June 30, 2003. Theadoption of SFAS 149 did not have a material effect on theCompany's financial position, results of operations or cashflows.

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

In December 2003, the FASBissued FASB Interpretation No. 46R which served to clarify guidance inFinancial 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 tocertain finance subsidiaries, as of October 1, 2003. The adoptionrequired the deconsolidation of certain finance subsidiaries, whichresulted in the amounts previously classified as mandatorily redeemablepreferred securities of subsidiary trusts, in the amount of $1.9billion, being reclassified to parent company subordinated debt in theaccompanying consolidated balance sheet as of December 31, 2003. Inaddition, the associated amounts previously recorded in minorityinterest and preferred dividends are now recorded as interest expensein the accompanying consolidated statement of operations. For theperiod from October 1, 2003 to December 31, 2003 the Company hasrecorded $49.8 million of interest expense related to these securities.In accordance with the requirements of FIN 46R, no amounts prior toadoption on October 1, 2003 have been reclassified. The Company willadopt the provisions of FIN 46R related to non-special purpose entitiesin the first quarter of 2004, in accordance with the provisions of FIN46R.   The Company is currently evaluating the impact of FIN 46Ron several operating joint ventures that the Company currently does notconsolidate.

3.    Acquisitions

Kern River

On March 27, 2002, the Company acquired Kern River. At the date ofacquisition, Kern River owned a 926-mile interstate pipelinetransporting Rocky Mountain and Canadian natural gas to markets inCalifornia, Nevada and Utah.

The Company paid $419.7 million,net of cash acquired and a working capital adjustment, for KernRiver's gas pipeline business. The acquisition has been accountedfor as a purchase business combination. The Company completed theallocation of the purchase price to the assets and liabilities acquiredduring the first quarter of 2003. The results of operations for KernRiver are included in the Company's results beginning March 27,2002.

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

|              |                              |
|--------------|------------------------------|
| •  | Opportunities for expansion; |

|              |                                                                    |
|--------------|--------------------------------------------------------------------|
| •  | Generally high credit quality shipperscontracting with Kern River; |

|              |                                          |
|--------------|------------------------------------------|
| •  | KernRiver's strong competitive position; |

67

----

|              |                                                                    |
|--------------|--------------------------------------------------------------------|
| •  | Exceptionaloperating track record and state-of-the-art technology; |

|              |                                                  |
|--------------|--------------------------------------------------|
| •  | Strong demand for gas in the Westernmarkets; and |

|              |                                 |
|--------------|---------------------------------|
| •  | An ample supply oflow-cost gas. |

There is no assurance that these attributes willcontinue to exist to the same degree as believed at the time of theacquisition.

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

The following tablesummarizes the estimated fair values of the assets acquired andliabilities assumed at the date of acquisition (in millions):

|                                |  |        |         |         |  |  |
|--------------------------------|--|--------|---------|---------|--|--|
| Cash                           |  | $      | 7.7     |    |
| Properties,plants andequipment |  |   | 796.8   |    |
| Goodwill                       |  |   | 33.9    |    |
| Otherassets                    |  |   | 171.7   |    |
| Total assetsacquired           |  |   | 1,010.1 |    |
| Currentliabilities             |  |   | (104.3  | )  |
| Long-termdebt                  |  |   | (482.0  | )  |
| Otherliabilities               |  |   | (1.5    | )  |
| Totalliabilities assumed       |  |   | (587.8  | )  |
| Netassets acquired             |  | $      | 422.3   |    |
|                                |

NorthernNatural Gas Company

On August 16, 2002, the Company acquiredNorthern Natural Gas from Dynegy Inc. Northern Natural Gas is a16,500-mile interstate pipeline extending from southwest Texas to theupper Midwest region of the United States.

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

The recognition of goodwill resulted from variousattributes of Northern Natural Gas' operations and business ingeneral. These attributes include, but are not limited to:

|              |                                                                             |
|--------------|-----------------------------------------------------------------------------|
| •  | Generally high credit quality shipperscontracting with Northern NaturalGas; |

|              |                                                  |
|--------------|--------------------------------------------------|
| •  | Northern Natural Gas'strong competitiveposition; |

|              |                                                             |
|--------------|-------------------------------------------------------------|
| •  | Strategic location in thehigh demand Upper Midwest markets; |

|              |                                                    |
|--------------|----------------------------------------------------|
| •  | Flexible access to an ample supply oflow-cost gas; |

|              |                                        |
|--------------|----------------------------------------|
| •  | Exceptional operatingtrack record; and |

|              |                             |
|--------------|-----------------------------|
| •  | Opportunities forexpansion. |

There is no assurance that these attributes willcontinue to exist to the same degree as believed at the time of theacquisition.

In connection with the acquisition of NorthernNatural Gas, MEHC issued $950.0 million of 11% Company-obligatedmandatorily redeemable preferred securities of a subsidiary trust dueAugust 31, 2011, with scheduled principal payments beginning in 2003,to Berkshire Hathaway.

68

----

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

|                                  |  |        |          |         |  |  |
|----------------------------------|--|--------|----------|---------|--|--|
| Cash                             |  | $      | 1.4      |    |
| Properties,plants andequipment   |  |   | 1,294.3  |    |
| Goodwill                         |  |   | 416.3    |    |
| Otherassets                      |  |   | 340.4    |    |
| Total assetsacquired             |  |   | 2,052.4  |    |
| Current portionof long-term debt |  |   | (450.0   | )  |
| Other currentliabilities         |  |   | (195.3   | )  |
| Long-termdebt                    |  |   | (499.8   | )  |
| Otherliabilities                 |  |   | (28.2    | )  |
| Totalliabilities assumed         |  |   | (1,173.3 | )  |
| Netassets acquired               |  | $      | 879.1    |    |
|                                  |

Thefollowing pro forma financial information of the Company represents theunaudited pro forma results of operations as if the Kern River andNorthern Natural Gas acquisitions, and the related financings, hadoccurred at the beginning of each period. These pro forma results havebeen prepared for comparative purposes only and do not profess to beindicative of the results of operations which would have been achievedhad these transactions been completed at the beginning of each year,nor are the results indicative of the Company's future results ofoperations (in millions):

|                                                                 |  |                       |         |        |  |        |         |        |  |  |
|-----------------------------------------------------------------|--|-----------------------|---------|--------|--|--------|---------|--------|--|--|
|                                                            |  | YearEnded December31, |
|                                                            |  | 2002                  |         | 2001   |
| Revenue                                                         |  | $                     | 5,299.4 |   |  | $      | 5,688.5 |   |
| Incomebefore cumulative effect of change in accountingprinciple |  |                  | 285.5   |   |  |   | 36.9    |   |
| Net incomeavailable to common and preferredshareholders         |  |                  | 285.5   |   |  |   | 32.3    |   |
|                                                                 |

HomeServices'Acquisitions

In 2003, HomeServices separately acquired fourreal estate companies for an aggregate purchase price of approximately$36.7 million net of cash plus working capital and certain otheradjustments. For the year ended December 31, 2002, these real estatecompanies had combined revenue of approximately $102.9 million on16,000 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' internallygenerated cash flows and revolving credit facility. In 2002,HomeServices separately acquired three real estate companies for anaggregate purchase price of approximately $106.1 million, net of cashacquired, plus working capital and certain other adjustments. For theyear ended December 31, 2001, these real estate companies had combinedrevenue of approximately $356.0 million on 42,000 closed sidesrepresenting $13.7 billion of sales volume. Additionally in 2003,HomeServices paid an earnout of $17.3 million based on 2002 financialperformance measures. These purchases were financed usingHomeServices' internally generated cash flows, revolving creditfacility and $40.0 million from MEHC, which was contributed toHomeServices as equity.

Yorkshire Swap

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

69

----

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

TheCompany paid $57.4 million, net of cash acquired of $353.8 million andtransaction costs, for 94.75% of the Yorkshire electricitydistribution business and related indebtedness. The acquisition hasbeen accounted for as a purchase business combination. The results ofoperations for Yorkshire are included in the Company's resultsbeginning September 21, 2001.

4.    Dispositions and OtherItems

CE Gas Asset Sale

In May 2002, CE Gas, anindirect wholly owned subsidiary of the Company, executed the sale ofseveral of its U.K. natural gas assets to Gaz de France forapproximately $200.0 million (£137.0 million). CE Gas sold itsinterest in four natural gas-producing fields located in the southernbasin of the U.K. North Sea (Anglia, Johnston, Schooner andWindermere). The transaction also included the sale of rights in fourgas fields (in development/construction) and three exploration blocksowned by CE Gas. The Company recorded pre-tax and after-tax income of$54.3 million and $41.3 million, respectively, which includes a writeoff of non-deductible goodwill of $49.6 million.

Telephone FlatSale

On October 16, 2001, the Company closed on a transactionthat transferred all properties and rights of the Telephone FlatProject, a geothermal development project in northern California toCalpine Corp. The Company recorded a pre-tax gain of $20.7 million andan after-tax gain of $12.2 million on the sale of the Telephone FlatProject.

Western States Sale

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

Teesside Power Limited("TPL")

In December 2001, the Companyrecorded a charge of $20.7 million, net of tax, representing an assetvaluation impairment charge under SFAS No. 121,"Accounting for the Impairment of Long-LivedAssets" ("SFAS 121") relating tothe Company's 15.4% interest in TPL. TPL owns and operatesa 1,875 MW combined cycle gas-fired power plant. Enron Corp.("Enron"), through its subsidiaries, owned a42.5% interest, operated the plant, and purchased 668 MW ofcapacity. Enron's subsidiary, which owns and operates TPL, is nowin administration and administrators have been appointed to run itsbusiness and are attempting to find a buyer.

Shareholders in TPLhad previously utilized TPL's taxable losses with an obligationto reimburse TPL later in the project's life. In May 2002, TPLexecuted a restructuring and stabilization agreement with its lenders.The contract included an agreement between TPL and its shareholderswith respect to the waiver of these repayment obligations. In May 2002,TPL released $35.7 million due to the repayment obligation being waivedwhich is reflected as a tax benefit in the provision for incometaxes.

70

----

5.    Properties, Plants andEquipment, Net

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

|                                               |  |                  |        |        |  |        |            |         |  |        |            |         |  |  |
|-----------------------------------------------|--|------------------|--------|--------|--|--------|------------|---------|--|--------|------------|---------|--|--|
|                                          |  | DepreciationLife |        | 2003   |  | 2002   |
| Utility generationand distributionsystem      |  |             | 10-50  |   |  | $      | 9,154,054  |    |  | $      | 8,165,140  |    |
| Interstatepipelines'assets                    |  |             | 3-87   |   |  |   | 3,483,672  |    |  |   | 2,260,799  |    |
| Independentpowerplants                        |  |             | 10-30  |   |  |   | 1,395,782  |    |  |   | 1,410,170  |    |
| Mineraland gas reserves and explorationassets |  |             | 5-30   |   |  |   | 554,780    |    |  |   | 500,422    |    |
| Utilitynon-operationalassets                  |  |             | 3-30   |   |  |   | 429,228    |    |  |   | 370,811    |    |
| Otherassets                                   |  |             | 3-10   |   |  |   | 146,286    |    |  |   | 131,577    |    |
| Totaloperatingassets                          |  |             |   |   |  |   | 15,163,802 |    |  |   | 12,838,919 |    |
| Accumulateddepreciation andamortization       |  |             |   |   |  |   | (4,260,643 | )  |  |   | (3,724,917 | )  |
| Netoperatingassets                            |  |             |   |   |  |   | 10,903,159 |    |  |   | 9,114,002  |    |
| Constructioninprogress                        |  |             |   |   |  |   | 277,820    |    |  |   | 1,170,485  |    |
| Properties,plants and equipment,net           |  |             |   |   |  | $      | 11,180,979 |    |  | $      | 10,284,487 |    |
|                                          |  |             |   |   |  |   |       |    |  |   |       |    |
|                                               |

Constructionin Progress

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

The first project is a natural gas-fired combined cycle unit with anestimated cost of $357 million, excluding allowance for funds usedduring construction. MidAmerican Energy will own and operate the plant.Commercial operation of the simple cycle mode began on May 5, 2003. Theplant, which will continue to be operated in simple cycle mode during2004, resulted in 327 MW of accredited capacity in the summer of 2003.The combined cycle operation is expected to commence in December 2004and achieve an expected additional accredited capacity of 190 MW.

The second project is currently under construction and will be a 790MW (based on expected accreditation) super-critical-temperature,low-sulfur coal-fired plant. MidAmerican Energy will operate the plantand hold an undivided ownership interest as a tenant in common with theother owners of the plant. MidAmerican Energy's ownershipinterest is 60.67% equating to 479 MW of output. MidAmericanEnergy expects its share of the estimated cost of the project to beapproximately $713 million, excluding allowance for funds used duringconstruction. Municipal, cooperative and public power utilities willown the remainder, which is a typical ownership arrangement for largebase-load plants in Iowa. On May 29, 2003, the Iowa Utilities Board("IUB") issued an order that approves theratemaking principles for the plant, and on June 27, 2003, MidAmericanEnergy received a certificate from the IUB allowing MidAmerican Energyto construct the plant. On February 12, 2003, MidAmerican Energyexecuted a contract with Mitsui & Co. Energy Development, Inc. forthe engineering, procurement and construction of the plant. OnSeptember 9, 2003, MidAmerican Energy began construction of the plant,which it expects to be completed in the summer of 2007. MidAmericanEnergy is also seeking an order from the IUB approving construction ofthe associated transmission facilities.

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

71

----

6.    Investment in CE Generation

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

|                                                                 |  |        |           |        |  |        |           |        |  |        |         |        |  |  |
|-----------------------------------------------------------------|--|--------|-----------|--------|--|--------|-----------|--------|--|--------|---------|--------|--|--|
|                                                            |  | 2003   |           | 2002   |  | 2001   |
| Revenue                                                         |  | $      | 487,422   |   |  | $      | 510,082   |   |  | $      | 565,838 |   |
| Incomebefore cumulative effect of change in accountingprinciple |  |   | 37,341    |   |  |   | 58,314    |   |  |   | 74,194  |   |
| Netincome                                                       |  |   | 34,874    |   |  |   | 58,314    |   |  |   | 58,808  |   |
| Currentassets                                                   |  |   | 124,168   |   |  |   | 202,490   |   |  |   |    |   |
| Totalassets                                                     |  |   | 1,708,742 |   |  |   | 1,865,036 |   |  |   |    |   |
| Currentliabilities                                              |  |   | 253,240   |   |  |   | 148,685   |   |  |   |    |   |
| Long-termdebt, including currentportion                         |  |   | 924,563   |   |  |   | 1,011,220 |   |  |   |    |   |
|                                                                 |

7.    OtherInvestments

The Williams Companies' Preferred Stock

On March 27, 2002, the Company invested $275.0 million in TheWilliams Companies, Inc. ("Williams") inexchange for shares of 9 7/8% cumulativeconvertible preferred stock of Williams. Dividends on Williamspreferred stock were received quarterly, commencing July 1, 2002. OnJune 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 theCompany in March 2002 for $275.0 million The Company recorded a pre-taxgain of $13.8 million on the transaction.

CE Casecnan NIAArbitration Settlement

On October 15, 2003, CE Casecnan Waterand Energy Company, Inc. ("CE Casecnan")closed a transaction settling the CE Casecnan NIA Arbitration, whicharose 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, CECasecnan recorded $31.9 million of other income and $24.4 million ofassociated income taxes. Under the terms of the settlement, CE Casecnanentered into an agreement with NIA which provided for the dismissalwith prejudice of all claims by CE Casecnan and counterclaims by NIA inthe NIA Arbitration. In connection with the settlement, NIA deliveredto CE Casecnan a ROP $97.0 million 8.375% Note due 2013 (the"ROP Note"), which contained a put provisiongranting CE Casecnan the right to put the ROP Note to the ROP for aprice of par plus accrued interest for a 30-day period commencing onJanuary 14, 2004. The ROP Note is included in the other current assetson the December 31, 2003 consolidated balance sheet. 

OnJanuary 14, 2004, CE Casecnan exercised its right to put the ROP Noteto the ROP and, in accordance with the terms of the put, CE Casecnanreceived $99.2 million (representing $97.0 million par value plusaccrued interest) from the ROP on January 21, 2004.

8.    Short-Term Debt

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

|                                        |  |        |         |        |  |        |        |        |  |  |
|----------------------------------------|--|--------|---------|--------|--|--------|--------|--------|--|--|
|                                   |  | 2003   |         | 2002   |
| MidAmericanEnergy commercialpaper      |  | $      | 48,000  |   |  | $      | 55,000 |   |
| HomeServicesrevolving creditfacilities |  |   | — |   |  |   | 24,750 |   |
| Other                                  |  |   | 36      |   |  |   | 32     |   |
| Totalshort-termdebt                    |  | $      | 48,036  |   |  | $      | 79,782 |   |
|                                        |

72

----

Parent Company Revolving CreditFacilities

In the second quarter of 2003, the Companyterminated its $400 million credit facility. On June 6, 2003, theCompany closed on a new $100 million revolving credit facility whichexpires on June 6, 2006. The facility supports letters of credit ofwhich $73.6 million were outstanding at December 31, 2003. Noborrowings were outstanding at December 31, 2003 or 2002. The facilitycarries a variable interest rate based on Libor and ranged from2.02% to 2.255% in 2003 and the prior facility rangedfrom 2.625% to 2.8625% in 2002.

MidAmericanEnergy Short-Term Debt

As of December 31, 2003, MidAmericanEnergy had in place a $370.4 million revolving credit facility thatsupports its $250.0 million commercial paper program and its variablerate pollution control revenue obligations. In addition, MidAmericanEnergy has a $5.0 million line of credit. As of December 31, 2003 and2002, commercial paper totaled $48.0 million and $55.0 million,respectively, for MidAmerican Energy. MHC Inc., an indirect whollyowned subsidiary of the Company, has a $4.0 million line of creditunder which no borrowings were outstanding at December 31, 2003 or2002. The commercial paper, bank notes and outstanding line of credithad a weighted average interest rate of 0.98% and 1.29%at December 31, 2003 and 2002, respectively.

HomeServicesRevolving Credit Facilities

Upon the expiration of its $65.0million senior secured revolving credit facility in November 2002,HomeServices entered into a new $125.0 million senior secured revolvingcredit agreement. The new revolving credit agreement has a term ofthree years and is secured by a pledge of the capital stock of all ofthe existing and future subsidiaries of HomeServices. Amountsoutstanding under this revolving credit facility bear interest, atHomeServices' option, at either the prime lending rate or LIBORplus a fixed spread of 1.25% to 2.25%, which varies basedon HomeServices' cash flow leverage ratio. The spread was1.25% at December 31, 2003 and 2002. No borrowings wereoutstanding at December 31, 2003 and $24.8 million was outstanding witha weighted average interest rate of 2.6661% at December 31,2002.

9.    Parent Company Senior Debt

Parent companysenior debt is unsecured senior obligations of MEHC and comprises thefollowing at December 31 (in thousands):

|                                          |  |        |           |         |  |        |           |         |  |  |
|------------------------------------------|--|--------|-----------|---------|--|--------|-----------|---------|--|--|
|                                     |  | 2003   |           | 2002    |
| 6.96%Senior Notes, due2003               |  | $      | —   |    |  | $      | 215,000   |    |
| 7.23%Senior Notes, due2005               |  |   | 260,000   |    |  |   | 260,000   |    |
| 4.625%Senior Notes, due2007              |  |   | 199,225   |    |  |   | 199,044   |    |
| 7.63%Senior Notes, due2007               |  |   | 350,000   |    |  |   | 350,000   |    |
| 3.50%Senior Notes, due2008               |  |   | 449,373   |    |  |   | —   |    |
| 7.52%Senior Notes, due2008               |  |   | 450,000   |    |  |   | 450,000   |    |
| 7.52%Senior Notes, due 2008 (SeriesB)    |  |   | 101,267   |    |  |   | 101,481   |    |
| 5.875%Senior Notes, due2012              |  |   | 499,898   |    |  |   | 499,887   |    |
| 8.48%Senior Notes, due2028               |  |   | 475,000   |    |  |   | 475,000   |    |
| Fair valueadjustments andother           |  |   | (6,885    | )  |  |   | (12,025   | )  |
| TotalParent Company SeniorDebt           |  |   | 2,777,878 |    |  |   | 2,538,387 |    |
| Lesscurrentportion                       |  |   | —   |    |  |   | (215,000  | )  |
| TotalLong-Term Parent Company SeniorDebt |  | $      | 2,777,878 |    |  | $      | 2,323,387 |    |
|                                          |

OnMay 16, 2003, MEHC issued $450.0 million, net of discount, of its3.5% Senior Notes with a final maturity on May 15, 2008. Theproceeds were used for general corporate purposes. On September 15,2003, MEHC repaid its $215.0 million, 6.96% Senior Notes.

73

----

|           |                                                                                                                   |
|-----------|-------------------------------------------------------------------------------------------------------------------|
| 10.  | Parent CompanySubordinated Debt/Company-Obligated Mandatorily Redeemable PreferredSecurities of Subsidiary Trusts |

Deconsolidation

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

The financialterms of MEHC's various subordinated debentures held by suchTrusts are essentially identical to the corresponding terms of thetrust preferred securities issued by such trusts. The followingsummarizes the terms and balances of the mandatorily redeemablepreferred securities of these unconsolidated trusts.

FinanceTrust Subsidiaries

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

Pursuant to PreferredSecurities Guarantee Agreements (collectively, the"Guarantees"), between MEHC and a trustee,MEHC has agreed irrevocably to pay to the holders of the TrustSecurities, to the extent that the applicable Trust has funds availableto make such payments, quarterly distributions, redemption payments andliquidation payments on the Trust Securities. Considered together, theundertakings contained in the Declarations, Junior Debentures,Indentures and Guarantees constitute full and unconditional guaranteeson a subordinated basis by MEHC of the Trusts' obligations underthe Trust Securities.

The balances presented for December31, 2003 are recorded in the accompanying consolidated balance sheet as"Parent company subordinated debt". Thebalances presented for December 31, 2002 are recorded in theaccompanying consolidated balance sheet as"Company-obligated mandatorily redeemable preferredsecurities of subsidiary trusts". The following tablepresents the balances of such Parent company subordinated debt andCompany-obligated mandatorily redeemable preferred securities ofsubsidiary trusts, respectively (in thousands):

|                                                                                                                                          |  |        |           |         |  |        |           |         |  |  |
|------------------------------------------------------------------------------------------------------------------------------------------|--|--------|-----------|---------|--|--------|-----------|---------|--|--|
|                                                                                                                                     |  | 2003   |           | 2002    |
| CalEnergyCapital Trust II — 6.25% preferred securities, due2012                                                                    |  | $      | 104,645   |    |  | $      | 155,538   |    |
| CalEnergyCapital Trust III — 6.5% preferred securities, due2027                                                                    |  |   | 269,980   |    |  |   | 269,980   |    |
| MidAmericanCapital Trust I — 11% preferred securities, due2010                                                                     |  |   | 454,772   |    |  |   | 454,772   |    |
| MidAmericanCapital Trust II — 11% preferred securities, due2012                                                                    |  |   | 323,000   |    |  |   | 323,000   |    |
| MidAmericanCapital Trust III — 11% preferred securities, due2012                                                                   |  |   | 800,000   |    |  |   | 950,000   |    |
| Fair valueadjustment                                                                                                                     |  |   | (80,251   | )  |  |   | (89,878   | )  |
| TotalParent company subordinated debt (2003)/Company-obligated mandatorilyredeemable preferred securities of subsidiary trusts(2002)     |  |   | 1,872,146 |    |  |   | 2,063,412 |    |
| Lesscurrentportion                                                                                                                       |  |   | (100,000  | )  |  |   | —   |    |
| Long-termParent company subordinated debt (2003)/Company-obligatedmandatorily redeemable preferred securities of subsidiary trusts(2002) |  | $      | 1,772,146 |    |  | $      | 2,063,412 |    |
|                                                                                                                                          |

Dividendsrelated to the company-obligated mandatorily redeemable preferredsecurities of subsidiary trusts, which were included in minorityinterest and preferred dividends on the consolidated statements ofoperations, for the years ended December 31, 2003, 2002 and 2001 were$170.2 million, $147.7 million and $80.1 million, respectively. For theyear ended December 31, 2003 an additional $49.8 million, representingthe amount of interest on parent company subordinated debt since theadoption of FIN 46R, was recorded as interest expense in theaccompanying consolidated statements of operations. 

MEHC ownsall of the common securities of the Trusts. The Trust Securities have aliquidation preference of $50 each (plus accrued and unpaid dividendsthereon to the date of payment) and represent 

74

----

undivided beneficial ownership interests ineach of the Trusts. The assets of the Trusts consist solely ofSubordinated Debentures of MEHC (collectively, the "JuniorDebentures") issued pursuant to their respectiveindentures. The indentures include agreements by MEHC to pay expensesand obligations incurred by the Trusts.

Prior to the TetonTransaction, each Trust Security issued by CalEnergy Capital Trust IIand III with a par value of $50 was convertible at the option of theholder at any time into shares of MEHC's common stock based on aspecified conversion rate. As a result of the Teton Transaction, inlieu of shares of MEHC's common stock, upon any conversion,holders of Trust Securities will receive $35.05 for each share ofcommon stock it would have been entitled to receive on conversion.

Distributions on the Trust Securities (and Junior Debentures) arecumulative, accrue from the date of initial issuance and are payablequarterly in arrears. The Junior Debentures are subordinated in rightof payment to all senior indebtedness of the Company and the JuniorDebentures are subject to certain covenants, events of default andoptional and mandatory redemption provisions, all as described in theJunior Debenture indentures.

The indentures relating to theCalEnergy Trusts II and III Trust Securities give MEHC the option todefer the interest payments due on the respective Junior Debentures forup to 20 consecutive quarters during which time the correspondingdistributions on the respective Trust Securities are deferred (butcontinue to accumulate and accrue interest). Similarly, the indenturesrelating to the MidAmerican Capital Trust I, II and III TrustSecurities give MEHC the option to defer the 11% interestpayment on the respective Junior Debentures for up to 10 consecutivesemi-annual periods during which time the corresponding 11%distributions on the respective Trust Securities are deferred (butcontinue to accumulate and accrue interest at the rate of 13%per annum). In addition, each declaration of trust establishing theMidAmerican Capital Trusts I, II and III Trust Securities and each ofthe related subscription agreements contains a provision prohibitingBerkshire Hathaway and its affiliates, who are the holders of all ofthe respective Trust Securities issued by such Trusts, fromtransferring such Trust Securities to a non-affiliated person absent anevent of default.

11.    Subsidiary and Project Debt

Each of MEHC's direct and indirect subsidiaries is organizedas a legal entity separate and apart from MEHC and its othersubsidiaries. Pursuant to separate project financing agreements, all orsubstantially all of the assets of each subsidiary are or may bepledged or encumbered to support or otherwise provide the security fortheir own project or subsidiary debt. It should not be assumed that anyasset of any such subsidiary will be available to satisfy theobligations of MEHC or any of its other such subsidiaries; provided,however, that unrestricted cash or other assets which are available fordistribution may, subject to applicable law and the terms of financingarrangements of such parties, be advanced, loaned, paid as dividends orotherwise distributed or contributed to MEHC or affiliates thereof.

The restrictions on distributions at these separate legal entitiesinclude various covenants including, but not limited to, leverageratios, interest coverage ratios and debt service coverage ratios. Asof December 31, 2003, the separate legal entities were in compliancewith all applicable covenants. However, Cordova Energy's 537 MWgas-fired power plant in the Quad Cities, Illinois area (the"Cordova Project") is currently prohibitedfrom making distributions by the terms of its indenture due to itsfailure to meet its debt service coverage ratio requirement.

75

----

Long-term debt of subsidiaries andprojects comprise the following at December 31 (in thousands):

|                                            |  |        |           |         |  |        |           |         |  |  |
|--------------------------------------------|--|--------|-----------|---------|--|--------|-----------|---------|--|--|
|                                       |  | 2003   |           | 2002    |
| MidAmericanFunding                         |  | $      | 700,000   |    |  | $      | 700,000   |    |
| MidAmericanEnergy                          |  |   | 1,128,647 |    |  |   | 1,053,418 |    |
| CEElectric UK                              |  |   | 2,467,214 |    |  |   | 2,573,589 |    |
| KernRiver                                  |  |   | 1,276,174 |    |  |   | 1,277,916 |    |
| NorthernNatural Gas                        |  |   | 799,472   |    |  |   | 799,406   |    |
| CordovaFunding                             |  |   | 214,761   |    |  |   | 223,762   |    |
| Salton SeaFundingCorporation               |  |   | 136,384   |    |  |   | 137,789   |    |
| CECasecnan                                 |  |   | 246,458   |    |  |   | 287,926   |    |
| LeyteProjects                              |  |   | 172,813   |    |  |   | 244,961   |    |
| HomeServices                               |  |   | 37,558    |    |  |   | 39,031    |    |
| Other,including fair valueadjustments      |  |   | (3,900    | )  |  |   | (5,498    | )  |
| TotalSubsidiary and ProjectDebt            |  |   | 7,175,581 |    |  |   | 7,332,300 |    |
| Lesscurrentportion                         |  |   | (500,941  | )  |  |   | (255,213  | )  |
| TotalLong-Term Subsidiary and ProjectDebt. |  | $      | 6,674,640 |    |  | $      | 7,077,087 |    |
|                                            |

MidAmericanFunding

The components of MidAmerican Funding, a wholly ownedsubsidiary of MEHC, Senior Notes and Bonds comprise the following atDecember 31 (in thousands):

|                             |  |        |         |        |  |        |         |        |  |  |
|-----------------------------|--|--------|---------|--------|--|--------|---------|--------|--|--|
|                        |  | 2003   |         | 2002   |
| 6.339%Senior Notes, due2009 |  | $      | 175,000 |   |  | $      | 175,000 |   |
| 6.75%Senior Notes, due2011  |  |   | 200,000 |   |  |   | 200,000 |   |
| 6.927%Senior Bonds, due2029 |  |   | 325,000 |   |  |   | 325,000 |   |
| TotalMidAmericanFunding     |  | $      | 700,000 |   |  | $      | 700,000 |   |
|                             |

MidAmericanFunding may use distributions that it receives from its subsidiaries tomake payments on the Notes and Bonds. These subsidiaries must makepayments on their own indebtedness before making distributions toMidAmerican Funding. These distributions are also subject to utilityregulatory restrictions agreed to by MidAmerican Energy in March 1999whereby it committed to the Iowa Utilities Board("IUB") to use commercially reasonableefforts to maintain an investment grade rating on its long-term debtand to maintain its common equity level above 42% of totalcapitalization unless circumstances beyond its control result in thecommon equity level decreasing to below 39% of totalcapitalization. MidAmerican Energy must seek the approval of the IUB ofa reasonable utility capital structure if MidAmerican Energy'scommon 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 ifMidAmerican Energy's equity level decreases to below 39%,even if the decrease is due to circumstances beyond the control ofMidAmerican Energy.

76

----

MidAmerican Energy

Thecomponents of MidAmerican Energy's Mortgage Bonds, PollutionControl Revenue Obligations and Notes comprise the following atDecember 31 (in thousands):

|                                                           |  |        |           |         |  |        |           |         |  |  |
|-----------------------------------------------------------|--|--------|-----------|---------|--|--------|-----------|---------|--|--|
|                                                      |  | 2003   |           | 2002    |
| Mortgagebonds:                                            |  |   |      |    |  |   |      |    |
| 7.125% Series,due2003                                     |  | $      | —   |    |  | $      | 100,000   |    |
| 7.7%Series, due2004                                       |  |   | 55,630    |    |  |   | 55,630    |    |
| 7%Series, due2005                                         |  |   | 90,500    |    |  |   | 90,500    |    |
| 7.375%Series, due2008                                     |  |   | —   |    |  |   | 75,000    |    |
| 7.45%Series, due2023                                      |  |   | —   |    |  |   | 6,940     |    |
| 6.95%Series, due2025                                      |  |   | —   |    |  |   | 12,500    |    |
| Pollutioncontrol revenueobligations:                      |  |   |      |    |  |   |      |    |
| 5.75%Series, due periodically through2003                 |  |   | —   |    |  |   | 4,320     |    |
| 6.7%Series, due2003                                       |  |   | —   |    |  |   | 1,000     |    |
| 6.1%Series, due2007                                       |  |   | 1,000     |    |  |   | 1,000     |    |
| 5.95%Series, due2023                                      |  |   | 29,030    |    |  |   | 29,030    |    |
| Variablerate series:                                      |  |   |      |    |  |   |      |    |
| Due 2016 and2017, 1.26% and1.64%                          |  |   | 37,600    |    |  |   | 37,600    |    |
| Due2023 (secured by general mortgage bond, 1.26% and1.64% |  |   | 28,295    |    |  |   | 28,295    |    |
| Due2023, 1.26% and1.64%                                   |  |   | 6,850     |    |  |   | 6,850     |    |
| Due2024, 1.26% and1.64%                                   |  |   | 34,900    |    |  |   | 34,900    |    |
| Due2025, 1.26% and1.64%                                   |  |   | 12,750    |    |  |   | 12,750    |    |
| Notes:                                                    |  |   |      |    |  |   |      |    |
| 6.375%Series, due2006                                     |  |   | 160,000   |    |  |   | 160,000   |    |
| 5.125%Series, due2013                                     |  |   | 275,000   |    |  |   | —   |    |
| 6.75%Series, due2031                                      |  |   | 400,000   |    |  |   | 400,000   |    |
| Obligationsunder capitallease                             |  |   | 2,060     |    |  |   | 2,161     |    |
| Unamortized debtpremium and discount,net                  |  |   | (4,968    | )  |  |   | (5,058    | )  |
| TotalMidAmericanEnergy                                    |  | $      | 1,128,647 |    |  | $      | 1,053,418 |    |
|                                                           |

OnFebruary 8, 2002, MidAmerican Energy issued $400 million of6.75% notes due in 2031. The proceeds were used to refinanceexisting debt and preferred securities and for other corporatepurposes. On March 11, 2002, MidAmerican Energy redeemed itsMidAmerican Energy-obligated mandatorily redeemable preferredsecurities of subsidiary trust at 100% of the principal amountplus accrued interest. 

On January 14, 2003, MidAmerican Energyissued $275 million of 5.125% medium-term notes due in 2013. Theproceeds were used to refinance existing debt and for other corporatepurposes.

On February 10, 2003, MidAmerican Energy redeemed all$75.0 million of its 7.375% series of mortgage bonds, and onMarch 17, 2003, it redeemed all $6.94 million of its 7.45%series of mortgage bonds. Additionally, MidAmerican Energy's7.125% series of mortgage bonds totaling $100 million matured onFebruary 3, 2003. On October 17, 2003, MidAmerican Energy redeemed all$12.5 million of its 6.95% series of mortgage bonds at103.48% of the principal amount.

77

----

CE Electric UK

The components ofCE Electric UK and its subsidiares' long-term debt comprise thefollowing at December 31 (in thousands):

|                                                                |  |        |           |        |  |        |           |        |  |  |
|----------------------------------------------------------------|--|--------|-----------|--------|--|--------|-----------|--------|--|--|
|                                                           |  | 2003   |           | 2002   |
| 6.853%Senior Notes, due2004                                    |  | $      | 117,112   |   |  | $      | 124,732   |   |
| 8.625%Bearer bonds, due2005                                    |  |   | 178,877   |   |  |   | 161,451   |   |
| 6.995%Senior Notes, due2007                                    |  |   | 236,174   |   |  |   | 236,081   |   |
| 6.496%Yankee Bonds, due2008                                    |  |   | 281,149   |   |  |   | 300,185   |   |
| Variable RateReset Trust Securities, due 2020 (4.39% and5.04%) |  |   | 287,539   |   |  |   | 260,028   |   |
| 8.875%Bearer bonds, due2020                                    |  |   | 178,644   |   |  |   | 161,360   |   |
| 9.25%Eurobonds, due2020                                        |  |   | 458,187   |   |  |   | 419,145   |   |
| 7.25%Sterling Bonds, due2022                                   |  |   | 351,242   |   |  |   | 316,829   |   |
| 7.25%Eurobonds, due2028                                        |  |   | 352,768   |   |  |   | 344,082   |   |
| 8.08%Trust Securities, due2038                                 |  |   | —   |   |  |   | 249,696   |   |
| CE Gas CreditFacility,6.67%                                    |  |   | 25,522    |   |  |   | —   |   |
| TotalCE ElectricUK                                             |  | $      | 2,467,214 |   |  | $      | 2,573,589 |   |
|                                                                |

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

OnJune 9, 2003, Yorkshire Power Group Limited, an indirect wholly ownedsubsidiary of CE Electric UK, completed the redemption in full of theoutstanding shares of the 8.08% Trust Securities, due June 30,2038, and paid $243.4 million in principal amount plus accrueddistributions. The redemption price was paid to holders of the trustsecurity on the redemption date.

During 2003, CE Electric UK andits subsidiaries purchased and retired approximately $50.0 million ofoutstanding indebtedness.

Kern River

The components ofKern River's long-term debt comprised the following at December31 (in thousands):

|                               |  |        |           |        |  |        |           |        |  |  |
|-------------------------------|--|--------|-----------|--------|--|--------|-----------|--------|--|--|
|                          |  | 2003   |           | 2002   |
| Constructionfinancingfacility |  | $      | —   |   |  | $      | 789,916   |   |
| 6.676%Senior Notes, due2016   |  |   | 464,000   |   |  |   | 488,000   |   |
| 4.893%Senior Notes, due2018   |  |   | 812,174   |   |  |   | —   |   |
| TotalKernRiver                |  | $      | 1,276,174 |   |  | $      | 1,277,916 |   |
|                               |

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

On May 1, 2003, Kern River Funding Corporation, a wholly ownedsubsidiary of Kern River, issued $836 million of its 4.893%Senior Notes with a final maturity on April 30, 2018. The proceeds wereused to repay all of the approximately $815 million of outstandingborrowings under Kern River's $875 million credit facility. KernRiver entered into this credit facility in 2002 to finance theconstruction of the 2003 Expansion Project. The credit facility wascanceled and a completion guarantee issued by MEHC was terminated.

78

----

Northern Natural Gas

Thecomponents of Northern Natural Gas' Senior Notes comprise thefollowing at December 31 (in thousands):

|                             |  |        |         |         |  |        |         |         |  |  |
|-----------------------------|--|--------|---------|---------|--|--------|---------|---------|--|--|
|                        |  | 2003   |         | 2002    |
| 6.875%Senior Notes, due2005 |  | $      | 100,000 |    |  | $      | 100,000 |    |
| 6.75%Senior Notes, due2008  |  |   | 150,000 |    |  |   | 150,000 |    |
| 7.00%Senior Notes, due2011  |  |   | 250,000 |    |  |   | 250,000 |    |
| 5.375%Senior Notes, due2012 |  |   | 300,000 |    |  |   | 300,000 |    |
| Unamortizeddebtdiscount     |  |   | (528    | )  |  |   | (594    | )  |
| TotalNorthern NaturalGas    |  | $      | 799,472 |    |  | $      | 799,406 |    |
|                             |

CordovaFunding

On September 10, 1999, Cordova Funding Corporation("Cordova Funding"), a wholly ownedsubsidiary of the Company, closed the $225.0 million aggregateprincipal amount financing for the construction of the Cordova Project.The proceeds were loaned to Cordova Energy and comprise the followingat December 31 (in thousands):

|                                    |  |        |         |        |  |        |         |        |  |  |
|------------------------------------|--|--------|---------|--------|--|--------|---------|--------|--|--|
|                               |  | 2003   |         | 2002   |
| 8.48%Senior Secured Bonds, due2019 |  | $      | 12,175  |   |  | $      | 12,685  |   |
| 8.64%Senior Secured Bonds, due2019 |  |   | 89,260  |   |  |   | 93,001  |   |
| 8.79%Senior Secured Bonds, due2019 |  |   | 29,885  |   |  |   | 31,137  |   |
| 8.82%Senior Secured Bonds, due2019 |  |   | 55,476  |   |  |   | 57,801  |   |
| 9.07%Senior Secured Bonds, due2019 |  |   | 27,965  |   |  |   | 29,138  |   |
| TotalCordovaFunding                |  | $      | 214,761 |   |  | $      | 223,762 |   |
|                                    |

MEHChas guaranteed a specified portion of the final scheduled principalpayment on December 15, 2019 on the Cordova Funding Senior SecuredBonds in an amount up to a maximum of $37.0 million. MEHC also providesa debt service reserve guarantee in an amount equal to the principal,premium, if any, and interest payment due on the bonds on the nextscheduled payment date which was equal to $13.5 million at December 31,2003.

As of December 31, 2003, Cordova Funding is currentlyprohibited from making distributions by the terms of its indenture dueto its failure to meet its debt service coverage ratio requirement.

Salton Sea Funding

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

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

79

----

CE Casecnan

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

|                                                 |  |        |         |        |  |        |         |        |  |  |
|-------------------------------------------------|--|--------|---------|--------|--|--------|---------|--------|--|--|
|                                            |  | 2003   |         | 2002   |
| 11.45%Senior Secured Series A Notes, due in2005 |  | $      | 91,250  |   |  | $      | 125,000 |   |
| 11.95%Senior Secured Series B Bonds, due in2010 |  |   | 155,208 |   |  |   | 162,926 |   |
| TotalCasecnan                                   |  | $      | 246,458 |   |  | $      | 287,926 |   |
|                                                 |

TheCE Casecnan Notes and Bonds are subject to redemption at theCompany's option as provided in the Trust Indenture. The CECasecnan Notes and Bonds are also subject to mandatory redemption basedon certain conditions.

Leyte Projects

The LeyteProjects term loans comprise the following at December 31 (inthousands):

|                                              |  |        |         |        |  |        |         |        |  |  |
|----------------------------------------------|--|--------|---------|--------|--|--------|---------|--------|--|--|
|                                         |  | 2003   |         | 2002   |
| MahanagdongProject 6.92% Term Loan, due2007  |  | $      | 72,151  |   |  | $      | 92,766  |   |
| MahanagdongProject 7.60% Term Loan, due2007  |  |   | 16,000  |   |  |   | 20,571  |   |
| Malitbog Project3.67% and 3.84%, due2005     |  |   | 26,378  |   |  |   | 40,890  |   |
| Malitbog Project9.176% Term Loan, due2006    |  |   | 14,628  |   |  |   | 22,677  |   |
| Upper MahiaoProject 4.42%, due2003           |  |   | — |   |  |   | 5,000   |   |
| Upper MahiaoProject 5.95% Term Loan, due2006 |  |   | 43,656  |   |  |   | 63,057  |   |
| TotalLeyteProjects                           |  | $      | 172,813 |   |  | $      | 244,961 |   |
|                                              |

MEHCprovides debt service reserve letters of credit in amounts equal to thenext semi-annual principal and interest payments due on the loans whichwas equal to $40.3 million and $47.7 million at December 31, 2003 and2002, respectively.

HomeServices

In November 1998,HomeServices issued $35.0 million of 7.12% fixed-rate privateplacement senior notes due in annual increments of $5.0 millionbeginning in 2004. As of December 31, 2003 and 2002, the balance of theHomeServices Senior Notes was $35.0 million.

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

80

----

Annual Repayments of Debt

Theannual repayments of debt for the years beginning January 1, 2004 andthereafter are as follows (in thousands):

|                                          |  |        |         |        |  |        |           |        |  |        |         |            |  |        |           |        |  |        |           |        |  |        |           |         |  |        |            |         |  |  |
|------------------------------------------|--|--------|---------|--------|--|--------|-----------|--------|--|--------|---------|------------|--|--------|-----------|--------|--|--------|-----------|--------|--|--------|-----------|---------|--|--------|------------|---------|--|--|
|                                     |  | 2004   |         | 2005   |  | 2006   |           | 2007   |  | 2008   |         | Thereafter |  | Total  |
| Parent,Subsidiary and Projectloans:      |  |   |    |   |  |   |      |   |  |   |    |       |  |   |      |   |  |   |      |   |  |   |      |    |  |   |       |    |
| ParentCompany SeniorDebt                 |  | $      | — |   |  | $      | 260,000   |   |  | $      | — |       |  | $      | 550,000   |   |  | $      | 1,000,000 |   |  | $      | 967,878   |    |  | $      | 2,777,878  |    |
| ParentCompany SubordinatedDebt           |  |   | 100,000 |   |  |   | 188,544   |   |  |   | 234,021 |       |  |   | 234,021   |   |  |   | 234,021   |   |  |   | 881,539   |    |  |   | 1,872,146  |    |
| MidAmericanFunding                       |  |   | — |   |  |   | —   |   |  |   | — |       |  |   | —   |   |  |   | —   |   |  |   | 700,000   |    |  |   | 700,000    |    |
| MidAmericanEnergy                        |  |   | 56,151  |   |  |   | 90,500    |   |  |   | 160,000 |       |  |   | 1,000     |   |  |   | —   |   |  |   | 820,996   |    |  |   | 1,128,647  |    |
| CEElectricUK                             |  |   | 117,112 |   |  |   | 178,877   |   |  |   | — |       |  |   | 236,174   |   |  |   | 281,149   |   |  |   | 1,653,902 |    |  |   | 2,467,214  |    |
| KernRiver                                |  |   | 61,366  |   |  |   | 62,784    |   |  |   | 66,128  |       |  |   | 69,472    |   |  |   | 72,816    |   |  |   | 943,608   |    |  |   | 1,276,174  |    |
| NorthernNaturalGas                       |  |   | — |   |  |   | 100,000   |   |  |   | — |       |  |   | —   |   |  |   | 150,000   |   |  |   | 549,472   |    |  |   | 799,472    |    |
| CordovaFunding                           |  |   | 8,100   |   |  |   | 7,875     |   |  |   | 4,500   |       |  |   | 4,163     |   |  |   | 4,725     |   |  |   | 185,398   |    |  |   | 214,761    |    |
| SaltonSea FundingCorporation             |  |   | 136,384 |   |  |   | —   |   |  |   | — |       |  |   | —   |   |  |   | —   |   |  |   | —   |    |  |   | 136,384    |    |
| CECasecnan                               |  |   | 49,360  |   |  |   | 54,752    |   |  |   | 36,016  |       |  |   | 37,730    |   |  |   | 37,730    |   |  |   | 30,870    |    |  |   | 246,458    |    |
| LeyteProjects                            |  |   | 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 valueadjustments    |  |   | — |   |  |   | —   |   |  |   | — |       |  |   | —   |   |  |   | —   |   |  |   | (3,900    | )  |  |   | (3,900     | )  |
| TotalParent, Subsidiary and ProjectLoans |  | $      | 600,941 |   |  | $      | 1,011,367 |   |  | $      | 535,702 |       |  | $      | 1,150,153 |   |  | $      | 1,785,441 |   |  | $      | 6,742,001 |    |  | $      | 11,825,605 |    |
|                                          |

FairValue

At December 31, 2003, the Company had fixed-ratelong-term debt of $11,369.4 million in principal amount and having afair value of $12,015.1 million. In addition, at December 31, 2003, theCompany had floating-rate obligations of $459.8 million that expose theCompany to the risk of increased interest expense in the event ofincreases in short-term interest rates.

12.    IncomeTaxes

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

|           |  |                        |         |         |  |        |         |         |  |        |         |         |  |  |
|-----------|--|------------------------|---------|---------|--|--------|---------|---------|--|--------|---------|---------|--|--|
|      |  | YearEnded 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 |    |
|           |

81

----

A reconciliation of the federal statutorytax rate to the effective tax rate applicable to income beforeprovision for income taxes follows:

|                                                      |  |        |         |         |  |        |         |         |  |        |        |         |  |  |
|------------------------------------------------------|--|--------|---------|---------|--|--------|---------|---------|--|--------|--------|---------|--|--|
|                                                 |  | 2003   |         | 2002    |  | 2001   |
| Federalstatutoryrate                                 |  |   | 35.0    | %  |  |   | 35.0    | %  |  |   | 35.0   | %  |
| Investmentand energy taxcredits                      |  |   | (0.5    | )  |  |   | (0.7    | )  |  |   | (1.0   | )  |
| Statetaxes, net of federal taxeffect                 |  |   | 1.4     |    |  |   | 1.2     |    |  |   | 3.2    |    |
| Goodwillamortization                                 |  |   | — |    |  |   | — |    |  |   | 5.9    |    |
| Dividendson preferred securities of subsidiarytrusts |  |   | (7.0    | )  |  |   | (8.1    | )  |  |   | (6.1   | )  |
| Taxeffect of foreignincome                           |  |   | 0.5     |    |  |   | (4.8    | )  |  |   | (2.5   | )  |
| Non-recurringitems on CE ElectricUK,                 |  |   |    |    |  |   |    |    |  |   |   |    |
| net of taxeffect of foreignincome                    |  |   | (0.5    | )  |  |   | (8.1    | )  |  |   | 19.2   |    |
| Dividendsreceiveddeduction                           |  |   | (1.2    | )  |  |   | (1.8    | )  |  |   | (2.6   | )  |
| Otheritems,net                                       |  |   | 1.8     |    |  |   | 2.8     |    |  |   | (1.5   | )  |
| Effectivetaxrate                                     |  |   | 29.5    | %  |  |   | 15.5    | %  |  |   | 49.6   | %  |
|                                                      |

TheInternal Revenue Service ("IRS")regularly examines the Company's federal income tax returns and,in the course of which, may propose adjustments to the Company'sfederal income tax liability reported on such returns. Tax years 1995through 2001 are currently under review. The Company's managementdoes not expect that the outcome of any proposed adjustments presentedto date by the IRS, individually or collectively, will have a materialadverse effect on the Company's financial position, results ofoperations, 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 |    |
| Incometaxes recoverable through futurerates      |  |   | 142,597   |    |  |   | 159,411   |    |
| Employeebenefits                                 |  |   | 43,005    |    |  |   | 65,537    |    |
| Reacquireddebt                                   |  |   | 5,665     |    |  |   | 4,914     |    |
| Fuel costrecoveries                              |  |   | 12,864    |    |  |   | —   |    |
| Other                                            |  |   | —   |    |  |   | 121       |    |
|                                             |  |   | 1,925,973 |    |  |   | 1,555,211 |    |
|                                             |  |   |      |    |  |   |      |    |
| Minimumpension liabilityadjustment               |  |   | (147,279  | )  |  |   | (140,854  | )  |
| Revenuesharingaccruals                           |  |   | (64,192   | )  |  |   | (48,861   | )  |
| Accrualsnot currently deductible for taxpurposes |  |   | (37,672   | )  |  |   | (59,083   | )  |
| Nuclearreserve anddecommissioning                |  |   | (35,955   | )  |  |   | (28,411   | )  |
| Deferredincome                                   |  |   | (37,819   | )  |  |   | (21,733   | )  |
| Fuel costrecoveries                              |  |   | —   |    |  |   | (9,558    | )  |
| NOL andcreditcarryforwards                       |  |   | (161,659  | )  |  |   | (8,290    | )  |
| Other                                            |  |   | (8,253    | )  |  |   | —   |    |
|                                             |  |   | (492,829  | )  |  |   | (316,790  | )  |
| Netdeferred incometaxes                          |  | $      | 1,433,144 |    |  | $      | 1,238,421 |    |
|                                                  |

82

----

13.    Preferred Securities ofSubsidiaries

The total outstanding cumulative preferredsecurities of MidAmerican Energy not subject to mandatory redemptionrequirements may be redeemed at the option of MidAmerican Energy atprices which, in the aggregate, total $32.6 million. The aggregatetotal the holders of all preferred securities outstanding atDecember  31, 2003 and 2002, are entitled to upon involuntarybankruptcy is $31.8 million plus accrued dividends. Annual dividendrequirements for all preferred securities outstanding at December 31,2003, total $1.3 million.

The total outstanding 8.061%cumulative preferred securities of a subsidiary of CE Electric UK,which are redeemable in the event of the revocation by the Secretary ofState 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 SeriesPreferred 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 6.7million shares of no par, zero-coupon convertible preferred stockvalued at $402.0 million to Berkshire Hathaway. In connection with theTeton Transaction, MEHC issued 34.6 million shares of no par, zerocoupon convertible preferred stock valued at $1,211.4 million. Eachshare of preferred stock is convertible at the option of the holderinto one share of MEHC's common stock subject to certainadjustments as described in MEHC's Amended and Restated Articlesof Incorporation.

While the convertible preferred stock does notvote generally with the common stock in the election of directors, theconvertible preferred stock gives Berkshire Hathaway the right to elect20% of MEHC's Board of Directors. The convertiblepreferred stock is convertible into common stock only upon theoccurrence of specified events, including modification or eliminationof the Public Utility Holding Company Act of 1935 so that holdingcompany registration would not be triggered by conversion.Additionally, the prior approval of the holders of convertiblepreferred stock is required for certain fundamental transactions byMEHC. Such transactions include, among others: (a) significant assetsales or dispositions; (b) merger transactions; (c) significantbusiness acquisitions or capital expenditures; (d) issuances orrepurchases of equity securities; and (e) the removal or appointment ofthe Chief Executive Officer.

MEHC's Articles ofIncorporation further provide that the convertible preferred shares:(a) are not mandatorily redeemable by MEHC or at the option of theholder; (b) participate in dividends and other distributions to commonshareholders as if they were common shares and otherwise possess nodividend rights; (c) are convertible into common shares on a 1 for 1basis, as adjusted for splits, combinations, reclassifications andother capital changes by MEHC; and (d) upon liquidation, except for ade minimus first priority distribution of $1 per share, share ratablywith the shareholders of common stock. Further, the aforementioneddividend and distribution arrangements cannot be modified without thepositive consent of the preferred shareholders.

15.    StockTransactions

As of December 31, 2003, there were 2,048,329options outstanding which are exercisable until the end of the term onMarch 14, 2008 at exercise prices ranging from $15.94 to $35.05 pershare.

On March 6, 2002, MEHC purchased 800,000 stock optionsheld 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, whichis equal to the difference between the option exercise prices and anagreed upon per share value.

On January 6, 2004, the Companypurchased a portion of the shares of common stock owned by Mr. Sokolfor an aggregate purchase price of $20.0 million.

16.    Accounting for Derivatives

Currency Exchange RateRisk

CE Electric UK entered into certain currency rate swapagreements for its Senior Notes with two large multi-national financialinstitutions. The swap agreements effectively convert the U.S. dollarfixed 

83

----

interest rate to a fixed rate in Sterling.For the $117.1 million of 6.853% Senior Notes outstanding atDecember 31, 2003, the agreements extend until maturity on December 30,2004 and convert the U.S. dollar interest rate to a fixed Sterling rateof 7.744%. For the $236.2 million of 6.995% Senior Notes,the agreements extend until maturity on December 30, 2007 and convertthe U.S. dollar interest rate to a fixed Sterling rate of7.737%. The estimated fair value of these swap agreements atDecember 31, 2003 is approximately $16.0 million based on quotes fromthe counterparty to these instruments and represents the estimatedamount that the Company would expect to pay if these agreements wereterminated.

A subsidiary of CE Electric UK entered into certaincurrency rate swap agreements for its Yankee Bonds with three largemulti-national financial institutions. The swap agreements effectivelyconvert the U.S. dollar fixed interest rate to a fixed rate inSterling. For the $281.1 million of the 6.496% Yankee Bondsoutstanding at December 31, 2003, the agreements extend until February25, 2008 and convert the U.S. dollar interest rate to a fixed Sterlingrate ranging from 7.3175% to 7.345%. The estimated fairvalue of these swap agreements at December 31, 2003 is approximately$62.6 million based on quotes from the counterparties to theseinstruments and represents the estimated amount that the Company wouldexpect to pay if these agreements were terminated.

17.    Regulatory Matters

MidAmerican Energy

Under two settlement agreements approved by the IUB, MidAmericanEnergy's Iowa retail electric rates in effect on December 31,2000, are effectively frozen through December 31, 2010. The settlementagreements specifically allow the filing of electric rate design orcost of service rate changes that are intended to keep MidAmericanEnergy's overall Iowa retail electric revenue unchanged, butcould result in changes to individual tariffs. The settlementagreements also each provide that portions of revenues associated withIowa retail electric returns on equity within specified ranges will berecorded as a regulatory liability to be used to offset a portion ofthe cost to Iowa customers of future generating plant investment.

Under the first settlement agreement, which was approved by the IUBon December 21, 2001, and is effective through December 31, 2005, anamount equal to 50% of revenues associated with returns onequity between 12% and 14%, and 83.33% of revenuesassociated with returns on equity above 14%, in each year isrecorded as a regulatory liability. The second settlement agreement,which was filed in conjunction with MidAmerican Energy'sapplication for ratemaking principles on a wind power project and wasapproved by the IUB on October 17, 2003, provides that during theperiod January 1, 2006 through December 31, 2010, an amount equal to40% of revenues associated with returns on equity between11.75% and 13%, 50% of revenues associated withreturns on equity between 13% and 14%, and 83.3%of revenues associated with returns on equity above 14%, in eachyear will be recorded as a regulatory liability. An amount equal to theregulatory liability is recorded as a regulatory charge in depreciationand amortization expense when the liability is accrued. Futuredepreciation will be reduced as a result of the credit applied togenerating plant balances as the regulatory liability is reduced. Theliability is being reduced as it is credited against plant in servicein amounts equal to the allowance for funds used during constructionassociated with generating plant additions. Interest expense is accruedon the portion of the regulatory liability related to prior years.

The 2003 settlement agreement also provides that if Iowa retailelectric returns on equity fall below 10% in any consecutive12-month period after January 1, 2006, MidAmerican Energy may seek tofile for a general increase in rates. However, prior to filing for ageneral increase in rates, MidAmerican Energy is required by thesettlement agreement to conduct 30 days of good faith negotiations withall of the signatories to the settlement agreement to attempt to avoida general increase in rates.

Illinois bundled electric rates arefrozen until 2007, subject to certain exceptions allowing forincreases, at which time bundled rates are subject to cost-basedratemaking. Illinois law provides for Illinois earnings above acomputed level of return on common equity to be shared equally betweenregulated retail electric customers and MidAmerican Energy. MidAmericanEnergy's computed level of return on common equity is based on arolling two-year average of the Monthly Treasury Long-Term AverageRate, as published by the Federal Reserve System, plus a premium of8.5% for 2000 through 2004 

84

----

and a premium of 12.5% for 2005 and2006. The two-year average above which sharing must occur for 2003 was13.73%. The law allows MidAmerican Energy to mitigate thesharing of earnings above the threshold return on common equity throughaccelerated recovery of electric assets.

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

CE ElectricUK

Most revenue of each Distribution License Holder("DLH") is controlled by a distribution pricecontrol formula. The current formula requires that regulateddistribution income per unit is increased or decreased each year byRPI-Xd where the Retail Price Index ("RPI")reflects the average of the 12-month inflation rates recorded for eachmonth in the previous July to December period. The distribution pricecontrol formula also reflects an adjustment factor("Xd") which was established by theregulatory 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 accountof the changes in system electrical losses, the number of customersconnected and the voltage at which customers receive the units ofelectricity distributed. This formula determines the maximum averageprice per unit of electricity distributed (in pence per kWh) which aDLH is entitled to charge. The distribution price control formulapermits DLHs to receive additional revenue due to increaseddistribution of units and a predetermined increase in end users. Theprice control does not seek to constrain the profits of a DLH from yearto year. It is a control on revenue that operates independently of mostof 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 astraight fixed variable rate design which provides that all fixed costsassignable to firm capacity customers, including a return on equity,are to be recovered through fixed monthly demand or capacityreservation charges which are not a function of throughput volumes.

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

18.    Pension Commitments

Domestic Operations

MidAmerican Energy sponsors anoncontributory defined benefit pension plan covering MEHC and itsdomestic energy subsidiaries. Benefit obligations under the plans arebased on participants' compensation, years of service and age atretirement. Funding to an external trust is based upon the actuariallydetermined costs of the plans and the requirements of the InternalRevenue Code and the Employee Retirement Income Security Act. TheCompany also maintains noncontributory, nonqualified supplementalexecutive retirement plans for active and retired participants.

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

85

----

Net periodic pension, supplementalretirement and postretirement benefit costs included the followingcomponents for the Company and the aforementioned affiliates for theyears ended December 31. For purposes of calculating the expectedreturn on pension plan assets, a market-related value is used.Market-related value is equal to fair value except for gains and losseson equity investments which are amortized into market-related value ona straight-line basis over five years.

Components of netperiodic benefit cost (in thousands):

|                                         |  |             |         |                     |  |        |         |         |  |        |         |         |  |        |         |         |  |        |         |         |  |        |         |         |  |  |
|-----------------------------------------|--|-------------|---------|---------------------|--|--------|---------|---------|--|--------|---------|---------|--|--------|---------|---------|--|--------|---------|---------|--|--------|---------|---------|--|--|
|                                    |  | PensionCost |         | Postretirement Cost |
|                                    |  | 2003        |         | 2002                |  | 2001   |         | 2003    |  | 2002   |         | 2001    |
| Servicecost                             |  | $           | 24,693  |                |  | $      | 20,235  |    |  | $      | 18,114  |    |  | $      | 8,175   |    |  | $      | 6,028   |    |  | $      | 4,357   |    |
| Interestcost                            |  |        | 34,533  |                |  |   | 34,177  |    |  |   | 33,027  |    |  |   | 16,065  |    |  |   | 13,928  |    |  |   | 10,418  |    |
| Expectedreturn on planassets            |  |        | (38,396 | )              |  |   | (38,213 | )  |  |   | (36,326 | )  |  |   | (6,008  | )  |  |   | (4,880  | )  |  |   | (4,032  | )  |
| Amortizationof net transitionobligation |  |        | (2,591  | )              |  |   | (2,591  | )  |  |   | (2,591  | )  |  |   | 4,110   |    |  |   | 4,110   |    |  |   | 4,110   |    |
| Amortizationof prior servicecost        |  |        | 2,761   |                |  |   | 2,729   |    |  |   | 2,729   |    |  |   | 593     |    |  |   | 425     |    |  |   | 425     |    |
| Amortizationof prior year (gain)loss    |  |        | 1,483   |                |  |   | (2,482  | )  |  |   | (3,894  | )  |  |   | 3,716   |    |  |   | 2,385   |    |  |   | 332     |    |
| Regulatoryexpense                       |  |        | 3,320   |                |  |   | 6,639   |    |  |   | — |    |  |   | — |    |  |   | — |    |  |   | — |    |
| Netperiodiccost                         |  | $           | 25,803  |                |  | $      | 20,494  |    |  | $      | 11,059  |    |  | $      | 26,651  |    |  | $      | 21,996  |    |  | $      | 15,610  |    |
|                                         |

Weighted-averageassumptions used to determine benefit obligations at December 31:

|                             |  |        |      |         |  |        |      |         |  |        |      |         |  |        |        |         |  |        |        |         |  |        |      |         |  |  |
|-----------------------------|--|--------|------|---------|--|--------|------|---------|--|--------|------|---------|--|--------|--------|---------|--|--------|--------|---------|--|--------|------|---------|--|--|
|                        |  | 2003   |      | 2002    |  | 2001   |      | 2003    |  | 2002   |      | 2001    |
| Discountrate                |  |   | 5.75 | %  |  |   | 5.75 | %  |  |   | 6.50 | %  |  |   | 5.75   | %  |  |   | 5.75   | %  |  |   | 6.50 | %  |
| Rateof compensationincrease |  |   | 5.00 | %  |  |   | 5.00 | %  |  |   | 5.00 | %  |  |   |   |    |  |   |   |    |  |
|                             |

Weighted-averageassumptions used to determine net benefit cost for years ended December31:

|                              |  |        |      |         |  |        |      |         |  |        |      |         |  |        |        |         |  |        |        |         |  |        |        |         |  |  |
|------------------------------|--|--------|------|---------|--|--------|------|---------|--|--------|------|---------|--|--------|--------|---------|--|--------|--------|---------|--|--------|--------|---------|--|--|
|                         |  | 2003   |      | 2002    |  | 2001   |      | 2003    |  | 2002   |      | 2001    |
| Discountrate                 |  |   | 5.75 | %  |  |   | 6.50 | %  |  |   | 7.00 | %  |  |   | 5.75   | %  |  |   | 6.50   | %  |  |   | 7.00   | %  |
| Expectedreturn on planassets |  |   | 7.00 | %  |  |   | 7.00 | %  |  |   | 7.00 | %  |  |   | 7.00   | %  |  |   | 7.00   | %  |  |   | 7.00   | %  |
| Rateof compensationincrease  |  |   | 5.00 | %  |  |   | 5.00 | %  |  |   | 5.00 | %  |  |   |   |    |  |   |   |    |  |   |   |    |
|                              |

Assumedhealth care cost trend rates at December 31:

|                                                              |  |        |       |         |  |        |      |         |  |  |
|--------------------------------------------------------------|--|--------|-------|---------|--|--------|------|---------|--|--|
|                                                         |  | 2003   |       | 2002    |
| Healthcare cost trend rate assumed for nextyear              |  |   | 11.00 | %  |  |   | 9.75 | %  |
| Ratethat the cost trend rate gradually declinesto            |  |   | 5.00  | %  |  |   | 5.25 | %  |
| Yearthat the rate reaches the rate it is assumed to remainat |  |   | 2010  |    |  |   | 2006 |    |
|                                                              |

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

|                                           |  |                             |        |                              |  |        |         |         |  |  |
|-------------------------------------------|--|-----------------------------|--------|------------------------------|--|--------|---------|---------|--|--|
|                                      |  | OnePercentage-PointIncrease |        | One Percentage-PointDecrease |
| Effect on total service and interestcost  |  | $                           | 5,484  |                         |  | $      | (4,136  | )  |
| Effect onpostretirement benefitobligation |  | $                           | 47,583 |                         |  | $      | (37,761 | )  |
|                                      |  |                        |   |                         |  |   |    |    |
|                                           |

86

----

The following table presents areconciliation of the beginning and ending balances of the benefitobligation, fair value of plan assets and the funded status of theaforementioned plans to the net amounts measured and recognized in theConsolidated Balance Sheets as of December  31(in thousands):

|                                                                |  |                 |          |                         |  |        |          |         |  |        |          |         |  |        |          |         |  |  |
|----------------------------------------------------------------|--|-----------------|----------|-------------------------|--|--------|----------|---------|--|--------|----------|---------|--|--------|----------|---------|--|--|
|                                                           |  | PensionBenefits |          | Postretirement Benefits |
|                                                           |  | 2003            |          | 2002                    |  | 2003   |          | 2002    |
| Reconciliationof the fair value of planassets:                 |  |            |     |                    |  |   |     |    |  |   |     |    |  |   |     |    |
| Fairvalue of plan assets at beginning ofyear                   |  | $               | 467,773  |                    |  | $      | 515,890  |    |  | $      | 122,655  |    |  | $      | 81,129   |    |
| Employercontributions                                          |  |            | 5,044    |                    |  |   | 4,681    |    |  |   | 32,566   |    |  |   | 24,034   |    |
| Participantcontributions                                       |  |            | —  |                    |  |   | —  |    |  |   | 6,371    |    |  |   | 4,505    |    |
| Actualreturn on planassets                                     |  |            | 105,438  |                    |  |   | (27,376  | )  |  |   | 15,853   |    |  |   | (4,528   | )  |
| Acquisition                                                    |  |            | —  |                    |  |   | —  |    |  |   | —  |    |  |   | 32,500   |    |
| Benefitspaid                                                   |  |            | (26,687  | )                  |  |   | (25,422  | )  |  |   | (19,596  | )  |  |   | (14,985  | )  |
| Fairvalue of plan assets at end ofyear                         |  | $               | 551,568  |                    |  | $      | 467,773  |    |  | $      | 157,849  |    |  | $      | 122,655  |    |
|                                                           |  |            |     |                    |  |   |     |    |  |   |     |    |  |   |     |    |
| Reconciliationof benefitobligation:                            |  |            |     |                    |  |   |     |    |  |   |     |    |  |   |     |    |
| Benefitobligation at beginning ofyear                          |  | $               | 593,179  |                    |  | $      | 518,208  |    |  | $      | 291,441  |    |  | $      | 194,917  |    |
| Servicecost                                                    |  |            | 24,693   |                    |  |   | 20,235   |    |  |   | 8,175    |    |  |   | 6,028    |    |
| Interestcost                                                   |  |            | 34,533   |                    |  |   | 34,177   |    |  |   | 16,065   |    |  |   | 13,928   |    |
| Participantcontributions                                       |  |            | —  |                    |  |   | —  |    |  |   | 6,371    |    |  |   | 4,505    |    |
| Planamendments                                                 |  |            | —  |                    |  |   | 520      |    |  |   | —  |    |  |   | 2,205    |    |
| Actuarial(gain)loss                                            |  |            | (5,670   | )                  |  |   | 45,461   |    |  |   | (5,023   | )  |  |   | 31,743   |    |
| Acquisition                                                    |  |            | —  |                    |  |   | —  |    |  |   | —  |    |  |   | 53,100   |    |
| Benefitspaid                                                   |  |            | (26,687  | )                  |  |   | (25,422  | )  |  |   | (19,596  | )  |  |   | (14,985  | )  |
| Benefitobligation at end ofyear                                |  | $               | 620,048  |                    |  | $      | 593,179  |    |  | $      | 297,433  |    |  | $      | 291,441  |    |
|                                                           |  |            |     |                    |  |   |     |    |  |   |     |    |  |   |     |    |
| Fundedstatus                                                   |  | $               | (68,480  | )                  |  | $      | (125,406 | )  |  | $      | (139,584 | )  |  | $      | (168,786 | )  |
| Amountsnotrecognized:                                          |  |            |     |                    |  |   |     |    |  |   |     |    |  |   |     |    |
| Unrecognizednet (gain)loss                                     |  |            | (12,907  | )                  |  |   | 61,289   |    |  |   | 83,509   |    |  |   | 102,095  |    |
| Unrecognizedprior servicecost                                  |  |            | 17,915   |                    |  |   | 20,676   |    |  |   | 5,451    |    |  |   | 6,043    |    |
| Unrecognizednet transition obligation(asset)                   |  |            | (792     | )                  |  |   | (3,383   | )  |  |   | 36,992   |    |  |   | 41,102   |    |
| Netamount recognized in the Consolidated BalanceSheets         |  | $               | (64,264  | )                  |  | $      | (46,824  | )  |  | $      | (13,632  | )  |  | $      | (19,546  | )  |
|                                                           |  |            |     |                    |  |   |     |    |  |   |     |    |  |   |     |    |
| Amountsrecognized in the Consolidated Balance Sheets consistof |  |            |     |                    |  |   |     |    |  |   |     |    |  |   |     |    |
| Prepaidbenefitcost                                             |  | $               | 39       |                    |  | $      | 11,825   |    |  | $      | —  |    |  | $      | 1,493    |    |
| Accruedbenefitliability                                        |  |            | (100,490 | )                  |  |   | (99,392  | )  |  |   | (13,632  | )  |  |   | (21,039  | )  |
| Intangibleassets                                               |  |            | 17,367   |                    |  |   | 20,082   |    |  |   | —  |    |  |   | —  |    |
| Regulatoryassets                                               |  |            | 18,820   |                    |  |   | 20,661   |    |  |   | —  |    |  |   | —  |    |
| Netamountrecognized                                            |  | $               | (64,264  | )                  |  | $      | (46,824  | )  |  | $      | (13,632  | )  |  | $      | (19,546  | )  |
|                                                                |

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

Although thesupplemental executive retirement plan had no assets as of December 31,2003, the Company has Rabbi trusts that hold corporate-owned lifeinsurance and other investments to provide 

87

----

funding for the future cash requirements.Because this plan is nonqualified, the fair value of these assets isnot included in the plan asset table below. The fair value of the Rabbitrust investments was $88.1 million and $76.2 million atDecember  31, 2003 and 2002, respectively.

PlanAssets

The Company's investment policy for itsdomestic pension and postretirement plans is to balance risk and returnthrough a diversified portfolio of high-quality equity and fixed incomesecurities. Equity targets for the pension and postretirement plans areas indicated in the tables below. Maturities for fixed incomesecurities are managed such that sufficient liquidity exists to meetnear-term benefit payment obligations. The plans retain outsideinvestment advisors to manage plan investments within the parametersoutlined by the Company's Pension Benefits Committee. Theweighted average return on assets assumption is based on historicalperformance 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:

|                  |  |                          |         |             |  |        |         |         |  |        |       |         |  |  |
|------------------|--|--------------------------|---------|-------------|--|--------|---------|---------|--|--------|-------|---------|--|--|
|             |  | Percentageof Plan Assets |
|             |  | at December31            |         | TargetRange |
| AssetCategory    |  | 2003                     |         | 2002        |  |
| Equitysecurities |  |                     | 70      | %      |  |   | 60      | %  |  |   | 65-75 | %  |
| Debtsecurities   |  |                     | 23      |        |  |   | 33      |    |  |   | 20-30 |    |
| Realestate       |  |                     | 7       |        |  |   | 7       |    |  |   | 0-10  |    |
| Other            |  |                     | — |        |  |   | — |    |  |   | 0-5   |    |
| Total            |  |                     | 100     | %      |  |   | 100     | %  |  |
|                  |

TheCompany's postretirement benefit plan asset allocation atDecember 31, 2003, and 2002, are as follows:

|                  |  |                          |     |             |  |        |     |         |  |        |       |         |  |  |
|------------------|--|--------------------------|-----|-------------|--|--------|-----|---------|--|--------|-------|---------|--|--|
|             |  | Percentageof Plan Assets |
|             |  | at December31            |     | TargetRange |
| AssetCategory    |  | 2003                     |     | 2002        |  |
| Equitysecurities |  |                     | 49  | %      |  |   | 34  | %  |  |   | 45-55 | %  |
| Debtsecurities   |  |                     | 48  |        |  |   | 48  |    |  |   | 45-55 |    |
| Other            |  |                     | 3   |        |  |   | 18  |    |  |   | 0-10  |    |
| Total            |  |                     | 100 | %      |  |   | 100 | %  |  |
|                  |

CashFlows

Employer contributions to the domestic pension andpostretirement plans are currently expected to be $5.1 million and$27.6 million, respectively, for 2004 based on current regulationswhich are subject to change. The Company's policy is tocontribute the minimum required amount to the pension plan and theamount expensed to its postretirement plans.

The Companysponsors defined contribution pension plans (401(k) plans) coveringsubstantially all domestic employees. The Company's contributionsvary depending on the plan but are based primarily on eachparticipant's level of contribution and cannot exceed the maximumallowable 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 lawthe Medicare Prescription Drug, Improvement and Modernization Act of2003 ("Medicare Act"). The Medicare Actintroduces a prescription drug benefit under Medicare as well as asubsidy to sponsors of retiree health care plans that provide a benefitto participants that is at least actuarially equivalent to MedicarePart D. The Medicare Act is expected to ultimately reduce theCompany's postretirement costs from what they would have beenabsent such changes. Detailed regulations pertaining to the MedicareAct have yet to be promulgated, and accordingly, the Company cannotdetermine precisely how it will implement the Medicare Act'sprovisions. Additionally, accounting guidance regarding the recognitionof the impacts of the Medicare Act is pending. Accordingly, the Companycontinues to evaluate its options and cannot predict the 

88

----

magnitude or timing of any resulting costssavings. As permitted by FASB Staff Position 106-1, the Company haselected to defer recognizing the effects of the Medicare Act in itspost-retirement plan accounting at December 31, 2003.

UnitedKingdom Operations

CE Electric UK, through a wholly-ownedsubsidiary, participates in the Electricity Supply Pension Scheme (the"UK Plan"), which provides pension and otherrelated defined benefits, based on final pensionable pay, tosubstantially all employees throughout the electricity supply industryin the United Kingdom.

Net periodic pension costs included thefollowing components for CE Electric UK for the years endedDecember  31. For purposes of calculating the expected return onpension plant assets, a market-related value is used. Market-relatedvalue is equal to fair value except for gains and losses on equityinvestments which are amortized into market-related value on astraight-line basis over five years.

Components of net periodicpension cost (in thousands):

|                                     |  |             |         |         |  |        |         |         |  |        |         |         |  |  |
|-------------------------------------|--|-------------|---------|---------|--|--------|---------|---------|--|--------|---------|---------|--|--|
|                                |  | PensionCost |
|                                |  | 2003        |         | 2002    |  | 2001   |
| Servicecost                         |  | $           | 9,485   |    |  | $      | 8,718   |    |  | $      | 7,781   |    |
| Interestcost                        |  |        | 62,632  |    |  |   | 56,817  |    |  |   | 51,440  |    |
| Expectedreturn on planassets        |  |        | (89,124 | )  |  |   | (85,927 | )  |  |   | (78,354 | )  |
| Amortizationof prior servicecost    |  |        | 1,472   |    |  |   | 1,202   |    |  |   | — |    |
| Curtailmentloss and foreignexchange |  |        | 537     |    |  |   | 6,463   |    |  |   | 7,061   |    |
| Netperiodicbenefit                  |  | $           | (14,998 | )  |  | $      | (12,727 | )  |  | $      | (12,072 | )  |
|                                     |

Asa result of the distribution price reviews in 1999, CE Electric UKimplemented a review of staffing requirements primarily in itsdistribution business. Following discussions with the trade unions, CEElectric UK put in place a workforce reduction program. The pensioncurtailment 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 determinebenefit obligations at December 31:

|                             |  |        |      |         |  |        |      |         |  |        |      |         |  |  |
|-----------------------------|--|--------|------|---------|--|--------|------|---------|--|--------|------|---------|--|--|
|                        |  | 2003   |      | 2002    |  | 2001   |
| Discountrate                |  |   | 5.5  | %  |  |   | 5.75 | %  |  |   | 5.75 | %  |
| Rateof compensationincrease |  |   | 2.75 | %  |  |   | 2.5  | %  |  |   | 2.5  | %  |
|                             |

Weighted-averageassumptions used to determine net benefit cost for years ended December31:

|                              |  |        |      |         |  |        |      |         |  |        |      |         |  |  |
|------------------------------|--|--------|------|---------|--|--------|------|---------|--|--------|------|---------|--|--|
|                         |  | 2003   |      | 2002    |  | 2001   |
| Discountrate                 |  |   | 5.5  | %  |  |   | 5.75 | %  |  |   | 5.75 | %  |
| Expectedreturn on planassets |  |   | 7.00 | %  |  |   | 7.00 | %  |  |   | 7.7  | %  |
| Rateof compensationincrease  |  |   | 2.75 | %  |  |   | 2.5  | %  |  |   | 2.5  | %  |
|                              |

89

----

The following table presents areconciliation of the beginning and ending balances of the benefitobligation, fair value of plan assets and the funded status of theaforementioned plans to the net amounts measured and recognized in theConsolidated Balance Sheets as of December  31 (inthousands):

|                                                                 |  |                 |           |         |  |        |           |         |  |  |
|-----------------------------------------------------------------|--|-----------------|-----------|---------|--|--------|-----------|---------|--|--|
|                                                            |  | PensionBenefits |
|                                                            |  | 2003            |           | 2002    |
| Reconciliationof the fair value of plan assets:                 |  |
| Fair value of planassets at beginning ofyear                    |  | $               | 976,427   |    |  | $      | 1,070,657 |    |
| Employercontributions                                           |  |            | 14,391    |    |  |   | 3,607     |    |
| Participantcontributions                                        |  |            | 4,742     |    |  |   | 3,006     |    |
| Actualreturn on planassets                                      |  |            | 152,246   |    |  |   | (144,298  | )  |
| Benefitspaid                                                    |  |            | (57,726   | )  |  |   | (57,719   | )  |
| Foreigncurrency exchange ratechanges                            |  |            | 116,136   |    |  |   | 101,174   |    |
| Fairvalue of plan assets at end ofyear                          |  | $               | 1,206,216 |    |  | $      | 976,427   |    |
| Reconciliationof benefit obligation:                            |  |
| Benefit obligation atbeginning ofyear                           |  | $               | 1,102,730 |    |  | $      | 974,079   |    |
| Servicecost                                                     |  |            | 9,485     |    |  |   | 8,718     |    |
| Interestcost                                                    |  |            | 62,632    |    |  |   | 56,817    |    |
| Participantcontributions                                        |  |            | 4,742     |    |  |   | 3,006     |    |
| Benefitspaid                                                    |  |            | (57,726   | )  |  |   | (57,719   | )  |
| SFAS 88Curtailment                                              |  |            | —   |    |  |   | 5,712     |    |
| Priorservicecost                                                |  |            | —   |    |  |   | 17,286    |    |
| Experience gainand change ofassumptions                         |  |            | 83,890    |    |  |   | (11,574   | )  |
| Foreigncurrency exchange ratechanges                            |  |            | 128,834   |    |  |   | 106,405   |    |
| Benefitobligation at end ofyear                                 |  | $               | 1,334,587 |    |  | $      | 1,102,730 |    |
| Fundedstatus                                                    |  |            | (128,371  | )  |  | $      | (126,303  | )  |
| Unrecognizednetloss                                             |  |            | 507,039   |    |  |   | 465,211   |    |
| Netamount recognized in the Consolidated BalanceSheets          |  | $               | 378,668   |    |  | $      | 338,908   |    |
| Amountsrecognized in the Consolidated Balance Sheets consistof: |  |
| Prepaid benefitcost                                             |  | $               | 378,668   |    |  | $      | 338,908   |    |
| Accruedbenefitliability                                         |  |            | (496,147  | )  |  |   | (457,317  | )  |
| Intangibleassets                                                |  |            | 16,604    |    |  |   | 16,433    |    |
| Accumulatedother comprehensiveincome                            |  |            | 479,543   |    |  |   | 440,884   |    |
| Netamountrecognized                                             |  | $               | 378,668   |    |  | $      | 338,908   |    |
|                                                                 |

Theaccumulated 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 liabilityas of December 31, 2003 and 2002 in the amount of $479.5 million and$440.9 million, respectively. The pension liability resulted from thedeclining market value of the pension plan assets during 2002 combinedwith a lower market interest rate used to value the plan'sliabilities. As of December 31, 2003 and 2002, the minimum pensionliability is measured as the amount of the plan's accumulatedbenefit obligation that is in excess of the plan's market valueof assets at December 31, 2003 and 2002 plus the prepaid asset balance.A charge equal to the excess was recorded to the Company'sstockholder's equity, net of income tax benefits, as a componentof comprehensive loss in the amount of $27.1 million and $308.6 millionin 2003 and 2002, respectively. This adjustment does not impact currentyear earnings, or the funding requirements of the plan.

90

----

Plan Assets

CEElectric UK's investment policy for its pension andpostretirement plans is to balance risk and return through adiversified portfolio of high-quality equity and fixed incomesecurities. Maturities for fixed income securities are managed suchthat sufficient liquidity exists to meet near-term benefit paymentobligations. The plans retain outside investment advisors to manageplan investments within the parameters outlined by the BenefitsCommittee of subsidiaries of CE Electric UK. The weighted averagereturn on assets assumption is based on historical performance for thetypes of assets in which the plans invest.

CE ElectricUK's pension plan asset allocation comprises the following atDecember 31:

|                  |  |                          |     |         |  |        |     |         |  |  |
|------------------|--|--------------------------|-----|---------|--|--------|-----|---------|--|--|
|             |  | Percentageof Plan Assets |
|             |  | at December31            |
| AssetCategory    |  | 2003                     |     | 2002    |
| Equitysecurities |  |                     | 64  | %  |  |   | 62  | %  |
| Debtsecurities   |  |                     | 26  |    |  |   | 27  |    |
| Realestate       |  |                     | 9   |    |  |   | 10  |    |
| Other            |  |                     | 1   |    |  |   | 1   |    |
| Total            |  |                     | 100 | %  |  |   | 100 | %  |
|                  |

CashFlows

Employer contributions to fund the ongoingliabilities of the UK Plan are expected to be approximately $14.0million in 2004. The next valuation of the UK Plan will take place asof March 31, 2004 and the results will be known later in the year. Thisvaluation will set a revised level of contributions for the next threeyears. If the valuation results in a deficit in the UK Plan then anappropriate level of funding to address the deficit will be agreed inaccordance with the UK Plan rules. The overall level of contributionspaid by the employer is expected to be one of the factors considered bythe regulator in setting the revised allowed prices which will takeeffect from April 1, 2005.

19.    Commitments andContingencies

Fuel, Energy and Operating LeaseCommitments

MidAmerican Energy has supply and relatedtransportation contracts for its fossil fueled generating stations. Asof December 31, 2003, the contracts, with expiration dates ranging from2004 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 2004through 2008, respectively, and $31.0 million for the total of theyears thereafter. MidAmerican Energy expects to supplement these coalcontracts with additional contracts and spot market purchases tofulfill its future fossil fuel needs. Additionally, MidAmerican Energyhas a supply and transportation contact for a natural gas-firedgenerating plant. The contract, which expires in 2012, requires minimumpayments of $0.8 million for 2004 and $6.2 million for each yearthereafter.

MidAmerican Energy also has contracts withnon-affiliated companies to purchase electric capacity. As of December31, 2003, the contracts, with expiration dates ranging from 2004 to2028, require minimum payments of $38.6 million, $3.6 million, $2.3million, $2.2 million and $2.2 million for the years 2004 through 2008,respectively, and $40.1 million for the total of the yearsthereafter.

MidAmerican Energy has various natural gas supplyand transportation contracts for its gas operations. As of December 31,2003, the minimum commitments under these contracts were $56.3 million,$43.8 million, $18.0 million, $13.9 million and $4.2 million for theyears 2004 through 2008, respectively, and $12.5 million for the totalof the years thereafter.

MidAmerican Energy is the lessee onoperating leases for coal railcars that contain guarantees of theresidual value of such equipment throughout the term of the leases.Events triggering the residual guarantees include termination of thelease, loss of the equipment or purchase of the equipment. Lease termsare for five years with provisions for extensions. As of December 31,2003, the maximum amount of such guarantees specified in these leasestotaled $31.0 million. These guarantees are not reflected on theConsolidated Balance Sheets.

91

----

MidAmerican Energy, Kern River, NorthernNatural Gas, CE Electric UK, CalEnergy Generation –Domestic and HomeServices have non-cancelable operating leasesprimarily for computer equipment, office space and rail cars. Theminimum payments under these leases are $53.1 million, $46.9 million,$41.0 million, $37.1 million and $27.0 million for the years 2004through 2008, respectively, and $85.0 million for the total of theyears thereafter.

Manufactured Gas Plants

The UnitedStates Environmental Protection Agency("EPA") and the state environmental agencieshave determined that contaminated wastes remaining at decommissionedmanufactured gas plant facilities may pose a threat to the publichealth or the environment if such contaminants are in sufficientquantities and at such concentrations as to warrant remedialaction.

MidAmerican Energy has evaluated or is evaluating 27properties that were, at one time, sites of gas manufacturing plants inwhich it may be a potentially responsible party. The purpose of theseevaluations is to determine whether waste materials are present,whether the materials constitute a health or environmental risk, andwhether MidAmerican Energy has any responsibility for remedial action.MidAmerican Energy is actively working with the regulatory agencies andhas received regulatory closure on four sites. MidAmerican Energy iscontinuing to evaluate several of the sites to determine the futureliability, if any, for conducting site investigations or other siteactivity.

MidAmerican Energy estimates the range of possiblecosts for investigation, remediation and monitoring for the sitesdiscussed above to be approximately $11 million to $30 million. As ofDecember 31, 2003, MidAmerican Energy has recorded a $14.0 millionliability for these sites and a corresponding regulatory asset forfuture recovery through the regulatory process. MidAmerican Energyprojects that these amounts will be incurred or paid over the next fouryears.

The estimated liability is determined through asite-specific cost evaluation process. The estimate includesincremental direct costs of remediation, site monitoring costs andcosts of compensation to employees for time expected to be spentdirectly on the remediation effort. The estimated recorded liabilitiesfor these properties are based upon preliminary data. Thus, actualcosts could vary significantly from the estimates. The estimate couldchange materially based on facts and circumstances derived from siteinvestigations, changes in required remedial action and changes intechnology relating to remedial alternatives. Insurance recoveries havebeen received for some of the sites under investigation. Thoserecoveries are intended to be used principally for acceleratedremediation, as specified by the IUB and are recorded as a regulatoryliability.

Although the timing of potential incurred costs andrecovery of such costs in rates may affect the results of operations inindividual periods, management believes that the outcome of theseissues will not have a material adverse effect on MidAmericanEnergy's financial position, results of operations or cashflows.

Air Quality

MidAmerican Energy'sgenerating facilities are subject to applicable provisions of the CleanAir Act and related air quality standards promulgated by the UnitedStates Environmental Protection Agency("EPA"). The Clean Air Act provides theframework for regulation of certain air emissions and permitting andmonitoring associated with those emissions. MidAmerican Energy believesit is in material compliance with current air quality requirements.

The EPA has in recent years implemented more stringent standards forozone and fine particulate matter. Designations regarding attainment ofthe eight-hour ozone standard have recently been reviewed by the EPA,and the EPA has concluded that the entire state of Iowa is inattainment of the standards. On December 4, 2003, the EPA announced thedevelopment of its Interstate Air Quality Rule, a proposal to requirecoal-burning power plants in 29 states and the District of Columbia toreduce emissions of sulfur dioxide("SO2") and nitrogen oxides("NOX") in an effort to reduceozone and fine particulate matter in the Eastern United States. It islikely that MidAmerican Energy's coal-burning facilities will beimpacted by this proposal.

In December 2000, the EPA concludedthat mercury emissions from coal-fired generating stations should beregulated. The EPA is currently considering two regulatory alternativesfor the regulation of 

92

----

mercury from coal-fired utilities asnecessary to protect public health. One of these alternatives wouldrequire reductions of mercury from all coal-fired facilities greaterthan 25 MW through application of Maximum Achievable Control Technologywith compliance assessed on a facility basis. The other alternativewould regulate the mercury emissions of coal-fired facilities that posea health hazard through a market based cap-and-trade mechanism similarto the SO2 allowance system. The EPA is currently under adeadline to finalize the mercury rule by December 2004. Any of thesenew or stricter standards could, in whole or in part, be superceded ormade more stringent by one of a number of multi-pollutant emissionreduction proposals currently under consideration at the federal level,including the "Clear Skies Initiative", andother pending legislative proposals that contemplate 70% to90% reductions of SO2, NOX and mercury, aswell as possible new federal regulation of carbon dioxide and othergasses that may affect global climate change.

Depending on theoutcome of the final regulations, MidAmerican Energy may be required toinstall control equipment on its generating stations or decrease thenumber of hours during which its generating stations operate. However,until final regulations are issued, the impact of the regulations onMidAmerican Energy cannot be predicted.

While legislative actionis necessary for the Clear Skies Initiative or other multi-pollutantemission reduction legislation to become effective, MidAmerican Energyhas implemented a planning process that forecasts the site-specificcontrols and actions required to meet emissions reductions of thisnature. On April 1, 2002, in accordance with an Iowa law passed in2001, MidAmerican Energy filed with the IUB its first multi-year planand budget for managing SO2 and NOX from itsgenerating facilities in a cost-effective manner. The plan providesspecific actions to be taken at each coal-fired generating facility andthe related costs and timing for each action. Mercury emissionsreductions were not addressed in the plan. On July 17, 2003, the IUBissued an order that affirmed an administrative law judge'sapproval of the plan, as amended. Accordingly, the IUB order providesthat the approved expenditures will not be subject to a subsequentprudence review in a future electric rate case, but it rejected thefuture application of a tracker mechanism to recover emission reductioncosts. However, pursuant to an unrelated rate settlement agreementapproved by the IUB on October 17, 2003, if prior to January 1, 2011,capital and operating expenditures to comply with environmentalrequirements cumulatively exceed $325 million, then MidAmerican Energymay seek to recover the additional expenditures from customers. At thistime, MidAmerican Energy does not expect these capital expenditures toexceed such amount.

Under the New Source Review("NSR") provisions of the Clean Air Act, autility is required to obtain a permit from the EPA or a stateregulatory agency prior to (1) beginning construction of a new majorstationary source of an NSR-regulated pollutant or (2) making aphysical or operational change (a "majormodification") to an existing facility that potentiallyincreases emissions, unless the changes are exempt under theregulations. In general, projects subject to NSR regulations aresubject to pre-construction review and permitting under the Preventionof Significant Deterioration ("PSD")provisions of the Clean Air Act. Under the PSD program, a project thatemits threshold levels of regulated pollutants must undergo a BestAvailable Control Technology analysis and evaluate the most effectiveemissions controls. These controls must be installed in order toreceive a permit. Violations of NSR regulations, which may be allegedby the EPA, states and environmental groups, among others, potentiallysubject a utility to material expenses for fines or other sanctions andremedies including requiring installation of enhanced pollutioncontrols and funding supplemental environmental projects.

Inrecent years, the EPA has requested from several utilities informationand support regarding their capital projects for various generatingplants. The requests were issued as part of an industry-wideinvestigation to assess compliance with the NSR and the New SourcePerformance Standards of the Clean Air Act. In December 2002 and April2003, MidAmerican Energy received requests from the EPA to providedocumentation related to its capital projects from January 1, 1980, tothe present for a number of its generating plants. MidAmerican Energyhas submitted information to the EPA in responses to these requests,and there are currently no outstanding data requests pending from theEPA. MidAmerican Energy cannot predict the outcome of these requests atthis time. However, on August 27, 2003, the EPA announced changes toits NSR rules that clarify what constitutes routine repair, maintenanceand replacement for purposes of triggering NSR requirements. The EPAconcluded equipment that is repaired, maintained or replaced with anexpenditure not greater than 20 percent of the value of the

93

----

source will not trigger the NSR provisionsof the Clean Air Act. After the NSR changes were announced, theEPA's enforcement branch indicated it would apply the clarifiedroutine repair, maintenance and replacement rules to its pendinginvestigation. A number of states and local air districts havechallenged the EPA's clarification of the rule and a panel of theU.S. Circuit Court of Appeals for the District of Columbia issued anorder on December 24, 2003 staying the EPA's implementation ofits clarification of the equipment replacement rule.

On August29, 2003, the EPA finalized requirements to reduce toxic air emissionsfrom stationary combustion turbines. These requirements apply toturbines used at pipeline compressor stations that are built afterJanuary  12, 2003. Kern River and Northern Natural Gas believethe existing turbines are exempt from the rule since the turbines werebuilt and installed at compressor stations built prior to January 12,2003. New turbine installations will likely require the installation ofequipment to reduce formaldehyde emissions and other pollutants to meetthe new requirements and could significantly increase the cost of newturbine installations.

On December 19, 2002, the EPA issuedproposed emission standards for hazardous air pollutants for stationaryreciprocating internal combustion engines, such as those used atpipeline compressor stations. The proposed standards would apply to allnew and certain existing reciprocating internal combustion enginesabove 500 horsepower that are located at facilities characterized underthe Clean Air Act as a "major source" oftoxic air pollutants. While the emission standards have not yet beenfinalized, the impact of any new regulation of hazardous air pollutantsfrom stationary reciprocating internal combustion engines could have asignificant impact on existing and new facilities.

Decommissioning Costs

Expected decommissioning costs forQuad Cities Station have been developed based on a site-specificdecommissioning study that includes decontamination, dismantling, siterestoration, dry fuel storage cost and an assumed shutdown date. QuadCities Station decommissioning costs are included in base rates in Iowatariffs.

MidAmerican Energy's share of expecteddecommissioning costs for Quad Cities Station, in 2003 dollars, is $260million 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 investmentof funds for decommissioning the Quad Cities Station. The fair value ofthe assets held in the trusts is reflected in Investments andNonregulated Property, Net.

MidAmerican Energy'sdepreciation and amortization expense included costs for Quad CitiesStation nuclear decommissioning of $8.3 million for each of the years2003, 2002 and 2001. The regulatory provision charged to expense isequal to the funding that is being collected in Iowa rates. Realizedand 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 and2001, respectively.

Nuclear Insurance

MidAmericanEnergy maintains financial protection against catastrophic lossassociated with its interest in Quad Cities Station through acombination of insurance purchased by Exelon Generation Company, LLC(the operator and joint owner of Quad Cities Station), insurancepurchased directly by MidAmerican Energy, and the mandatoryindustry-wide loss funding mechanism afforded under the Price-AndersonAmendments Act of 1988. The general types of coverage are: nuclearliability, property coverage and nuclear worker liability.

Exelon Generation purchases nuclear liability insurance for QuadCities Station in the maximum available amount of $300 million, whichincludes coverage for MidAmerican Energy's ownership. Inaccordance with the Price-Anderson Amendments Act of 1988, excessliability protection above that amount is provided by a mandatoryindustry-wide Secondary Financial Protection program under which thelicensees of nuclear generating facilities could be assessed forliability incurred due to a serious nuclear incident at any commercialnuclear reactor in the United States. Currently, MidAmericanEnergy's aggregate maximum potential share of an assessment forQuad Cities Station is approximately $50.3 million per incident,payable in installments not to exceed $5 million annually.

94

----

The property insurance covers propertydamage, stabilization and decontamination of the facility, disposal ofthe decontaminated material and premature decommissioning arising outof a covered loss. For Quad Cities Station, Exelon Generation purchasedprimary and excess property insurance protection for the combinedinterests in Quad Cities Station, with coverage limits totaling $2.1billion. MidAmerican Energy also directly purchased extra expense orbusiness interruption coverage for its share of replacement power andother extra expenses in the event of a covered accidental outage atQuad Cities Station. The property and related coverages purchaseddirectly by MidAmerican Energy and by Exelon Generation, which includesthe interests of MidAmerican Energy, are underwritten by an industrymutual insurance company and contain provisions for retrospectivepremium assessments should two or more full policy-limit losses occurin one policy year. Currently, the maximum retrospective amounts thatcould be assessed against MidAmerican Energy from industry mutualpolicies 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 anindustry-wide guaranteed-cost policy with an aggregate limit of $300million for the nuclear industry as a whole, which is in effect tocover tort claims in nuclear-related industries.

The currentPrice-Anderson Act expired in August 2002 and is pending congressionalaction for reauthorization. Its contingent financial obligations stillapply to reactors licensed by the Nuclear Regulatory Commission as ofits expiration date. It is anticipated that the Price-Anderson Act willbe renewed with increased third party financial protection requirementsfor nuclear incidents.

Natural Gas Commodity Litigation

MidAmerican Energy is one of dozens of companies named as defendantsin a January 20, 2004 consolidated class action lawsuit filed in theU.S. District Court for the Southern District of New York. The suitalleges that the defendants have engaged in unlawful manipulation ofthe prices of natural gas futures and options contracts traded on theNew York Mercantile Exchange ("NYMEX") duringthe period January 1, 2000 to December 31, 2002. MidAmerican Energy ismentioned as a company that has engaged in wash trades on Enron Online(an electronic trading platform) that had the effect of distortingprices for gas trades on the NYMEX. The plaintiffs to the class actiondo not specify the amount of alleged damages. At this time, MidAmericanEnergy does not believe that it has any material exposure in thislawsuit.

The original complaint in this matter, CornerstonePropane Partners, L.P. v. Reliant, et al.("Cornerstone"), was filed on August 18,2003 in the United States District Court, Southern District of New Yorknaming MidAmerican Energy and the Company. On October 1, 2003, a secondcomplaint , Roberto, E. Calle Gracey, et al. ("CalleGracey"), was filed in the same court but did not nameMidAmerican Energy or the Company. On November 14, 2003, a thirdcomplaint, Dominick Viola ("Viola"), etal., was filed in the same court and named MidAmerican Energy andMEHC as defendants. On November 19, 2003, an Order of VoluntaryDismissal Without Prejudice of MEHC was entered by the court dismissingMEHC from the Cornerstone and Viola complaints. OnDecember 5, 2003, the court entered Pretrial Order No. 1, which amongother procedural matters, ordered the consolidation of theCornerstone, Calle Gracey and Viola complaints andpermitted plaintiffs to file an amended complaint in this matter. OnJanuary 20, 2004, plaintiffs filed In Re: Natural Gas CommodityLitigation as the amended complaint reasserting their previousallegations. Unless extended by agreement of the parties or by courtorder, MidAmerican Energy's answer and/or responsive pleading inthis matter is due February 19, 2004. MidAmerican Energy willcoordinate with the other defendants and vigorously defend theallegations against it.

Philippines

CECasecnan Construction Contract Arbitration

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

In 2001, the Contractor filed aRequest for Arbitration (and two supplements) with the InternationalChamber of Commerce ("ICC") seeking schedulerelief of up to 153 days, compensation for alleged 

95

----

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

On November 7, 2002, the ICC issued thearbitration tribunal's partial award with respect to theContractor's force majeure claims. The arbitration panel awardedthe Contractor 18 days of schedule relief in the aggregate for all ofthe force majeure events and awarded the Contractor $3.8 million to theextent losses are not covered by insurance. All of theContractor's other claims with respect to force majeure andgeologic conditions were denied. If the Contractor were to prevail onthe Contractor's claim that the delay liquidated damages clauseis unenforceable, CE Casecnan would not be entitled to collect suchdelay damages for the period from March 31, 2001 through December 11,2001. If the Contractor were to prevail in the Contractor'srepudiation claim and prove quantum meruit damages in excess of amountspaid to the Contractor, CE Casecnan could be liable to make additionalpayments to the Contractor. CE Casecnan believes all of suchallegations and claims are without merit and is vigorously contestingthe Contractor's claims. CE Casecnan believes that an award willbe issued by the ICC in 2004.

CE Casecnan StockholderLitigation

Pursuant to the share ownership adjustmentmechanism in the CE Casecnan stockholder agreement, which is based uponpro forma financial projections of the Casecnan project preparedfollowing 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"), thatMEHC's ownership interest in CE Casecnan had increased to100% effective from commencement of commercial operations. InApril 2002, CE Casecnan Ltd. and LPG entered into a status quoagreement pursuant to which CE Casecnan Ltd. agreed not to take anyaction to exercise control over or transfer LPG's shares in CECasecnan. On July 8, 2002, LPG filed a complaint in the Superior Courtof the State of California, City and County of San Francisco against,among others, CE Casecnan Ltd. and MEHC. In the complaint, LPG seekscompensatory and punitive damages for alleged breaches of thestockholder agreement and alleged breaches of fiduciary dutiesallegedly owed by CE Casecnan Ltd. and MEHC to LPG. The complaint alsoseeks injunctive relief against all defendants and a declaratoryjudgment that LPG is entitled to maintain a 15% interest in CECasecnan. On January 21, 2004, CE Casecnan Ltd. and LPG entered into asecond status quo agreement pursuant to which the parties agreed to setaside certain distributions related to the shares subject to the LPGdispute and not distribute such funds without at least 15 days priornotice to LPG. Accordingly, 15% of the dividend distributiondeclared on January 21, 2004 was set aside by CE Casecnan in anunsecured CE Casecnan account. The impact, if any, of this litigationon the Company cannot be determined at thistime.

96

----

20.    Segment Information:

The Company has identified seven reportable segments principallybased on management structure: MidAmerican Energy, Kern River, NorthernNatural Gas, CE Electric UK, CalEnergy Generation-Domestic, CalEnergyGeneration-Foreign, and HomeServices. Information related to theCompany's reportable operating segments is shown below (inthousands).

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

97

----

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

98

----

|                                     |  |                   |            |        |  |        |            |        |  |        |            |        |  |  |
|-------------------------------------|--|-------------------|------------|--------|--|--------|------------|--------|--|--------|------------|--------|--|--|
|                                |  | Asof December 31, |
|                                |  | 2003              |            | 2002   |  | 2001   |
| **Identifiableassets:**             |  |
| MidAmericanEnergy                   |  | $                 | 6,596,849  |   |  | $      | 6,411,143  |   |  | $      | 6,215,968  |   |
| KernRiver                           |  |              | 2,200,201  |   |  |   | 1,797,850  |   |  |   | —    |   |
| NorthernNaturalGas                  |  |              | 2,167,621  |   |  |   | 2,162,367  |   |  |   | —    |   |
| CEElectricUK                        |  |              | 5,038,880  |   |  |   | 4,714,459  |   |  |   | 4,340,147  |   |
| CalEnergyGeneration –Domestic |  |              | 865,223    |   |  |   | 873,357    |   |  |   | 870,664    |   |
| CalEnergyGeneration –Foreign  |  |              | 949,237    |   |  |   | 974,852    |   |  |   | 950,035    |   |
| HomeServices                        |  |              | 567,736    |   |  |   | 488,324    |   |  |   | 322,552    |   |
| Segmentidentifiableassets           |  |              | 18,385,747 |   |  |   | 17,422,352 |   |  |   | 12,699,366 |   |
| Corporate/other                     |  |              | 782,442    |   |  |   | 1,012,568  |   |  |   | 295,219    |   |
| Totalidentifiableassets             |  | $                 | 19,168,189 |   |  | $      | 18,434,920 |   |  | $      | 12,994,585 |   |
| **Long-livedassets:**               |  |
| MidAmericanEnergy                   |  | $                 | 5,524,279  |   |  | $      | 5,385,328  |   |  | $      | 5,247,817  |   |
| KernRiver                           |  |              | 2,010,113  |   |  |   | 1,682,934  |   |  |   | —    |   |
| NorthernNaturalGas                  |  |              | 1,809,623  |   |  |   | 1,818,469  |   |  |   | —    |   |
| CEElectricUK                        |  |              | 4,489,306  |   |  |   | 3,936,598  |   |  |   | 3,650,385  |   |
| CalEnergyGeneration –Domestic |  |              | 593,580    |   |  |   | 594,282    |   |  |   | 571,404    |   |
| CalEnergyGeneration –Foreign  |  |              | 621,674    |   |  |   | 724,908    |   |  |   | 805,050    |   |
| HomeServices                        |  |              | 418,999    |   |  |   | 384,899    |   |  |   | 262,175    |   |
| Segmentlong-livedassets             |  |              | 15,467,574 |   |  |   | 14,527,418 |   |  |   | 10,536,831 |   |
| Corporate/other                     |  |              | 19,048     |   |  |   | 15,201     |   |  |   | 7,019      |   |
| Totallong-livedassets               |  | $                 | 15,486,622 |   |  | $      | 14,542,619 |   |  | $      | 10,543,850 |   |
|                                     |

Theremaining differences from the segment amounts to the consolidatedamounts described as "Corporate/Other" relateprincipally to the corporate functions including administrative costs,corporate cash and related interest income, corporate interestexpenses, intersegment eliminations, and fair value adjustmentsrelating to acquisitions.

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

|                                                           |  |                   |           |           |  |                    |         |              |  |                             |         |               |  |        |           |         |  |        |         |         |  |        |         |         |  |        |           |         |  |  |
|-----------------------------------------------------------|--|-------------------|-----------|-----------|--|--------------------|---------|--------------|--|-----------------------------|---------|---------------|--|--------|-----------|---------|--|--------|---------|---------|--|--------|---------|---------|--|--------|-----------|---------|--|--|
|                                                      |  | MidAmericanEnergy |           | KernRiver |  | NorthernNaturalGas |         | CEElectricUK |  | CalEnergyGenerationDomestic |         | Home-Services |  | Total  |
| **Balance,January 1,2002**                                |  | $                 | 2,160,004 |      |  | $                  | — |         |  | $                           | — |          |  | $      | 1,104,262 |    |  | $      | 142,726 |    |  | $      | 231,554 |    |  | $      | 3,638,546 |    |
| Goodwillfrom acquisitions during theyear                  |  |              | —   |      |  |               | 32,547  |         |  |                        | 414,721 |          |  |   | 56,626    |    |  |   | — |    |  |   | 108,914 |    |  |   | 612,808   |    |
| Goodwillwritten off related to the sale of a businessunit |  |              | —   |      |  |               | — |         |  |                        | — |          |  |   | (49,587   | )  |  |   | — |    |  |   | — |    |  |   | (49,587   | )  |
| Othergoodwill 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 |    |
| Goodwillfrom acquisitions during theyear                  |  |              | —   |      |  |               | — |         |  |                        | — |          |  |   | —   |    |  |   | — |    |  |   | 26,648  |    |  |   | 26,648    |    |
| Othergoodwill 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) | Othergoodwill adjustments include deferred tax, foreign currencytranslation, stock options and purchase priceadjustments. |
|-----|---------------------------------------------------------------------------------------------------------------------------|

99

----

Item 9.    Changes in andDisagreements with Accountants on Accounting and FinancialDisclosure

None.

Item 9A.    Controls andProcedures

An evaluation was performed under the supervisionand with the participation of the Company's management, includingthe Chief Executive Officer and Chief Financial Officer of MEHC,regarding the effectiveness of the design and operation of theCompany's disclosure controls and procedures (as defined in Rule13a-15(e) promulgated under the Securities and Exchange Act of 1934, asamended) as of December 31, 2003. Based on that evaluation, theCompany's management, including the Chief Executive Officer andChief Financial Officer of MEHC, concluded that the Company'sdisclosure controls and procedures were effective. There have been nosignificant changes in the Company's internal controls or inother factors that could significantly affect internalcontrols.

100

----

PART III

Item10.    Directors and Executive Officers of the Registrant.

MEHC's management structure is organized functionally and thecurrent executive officers and directors of MEHC and their positionsare as follows:

|                    |  |                                                               |  |  |  |  |
|--------------------|--|---------------------------------------------------------------|--|--|--|--|
| Name               |  | Position                                                      |
| David L.Sokol      |  | Chairmanof the Board, Chief Executive Officer andDirector     |
| Gregory E. Abel    |  | President, ChiefOperating Officer and Director                |
| Patrick J.Goodman  |  | Senior Vice President and Chief FinancialOfficer              |
| Douglas L.Anderson |  | Senior Vice President, General Counsel and CorporateSecretary |
| Keith D. Hartje    |  | Senior VicePresident and Chief Administrative Officer         |
| Warren E.Buffett   |  | Director                                                      |
| Walter ScottJr.    |  | Director                                                      |
| Marc D.Hamburg     |  | Director                                                      |
| W. DavidScott      |  | Director                                                      |
| Edgar D.Aronson    |  | Director                                                      |
| John K.Boyer       |  | Director                                                      |
| Stanley J.Bright   |  | Director                                                      |
| Richard R.Jaros    |  | Director                                                      |
|                    |

Officers areelected annually by the Board of Directors. There are no familyrelationships among the executive officers, nor any arrangements orunderstanding between any officer and any other person pursuant towhich the officer was appointed.

Set forth below is certaininformation, as of January 1, 2004, with respect to each of theforegoing officers and directors:

DAVID L. SOKOL, 47, Chairmanof the Board of Directors and Chief Executive Officer. Mr. Sokol hasbeen CEO since April 19, 1993 and served as President of MEHC fromApril 19, 1993 until January 21, 1995. Mr. Sokol has been Chairman ofthe 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 KiewitEnergy Company, which at that time was a wholly owned subsidiary ofPeter Kiewit & Sons', Inc., and Ogden Projects, Inc.

GREGORY E. ABEL, 41, President, Chief Operating Officer andDirector. Mr. Abel joined MEHC in 1992 and initially served as VicePresident and Controller. Mr. Abel is a Chartered Accountant and from1984 to 1992 he was employed by Price Waterhouse. As a Manager in theSan Francisco office of Price Waterhouse, he was responsible forclients in the energy industry.

PATRICK J. GOODMAN, 37, SeniorVice President and Chief Financial Officer. Mr. Goodman joined MEHC in1995 and served in various accounting positions including Senior VicePresident and Chief Accounting Officer. Prior to joining MEHC, Mr.Goodman was a financial manager for National Indemnity Company and asenior associate at Coopers & Lybrand.

DOUGLAS L. ANDERSON,45, Senior Vice President and General Counsel. Mr. Anderson joined MEHCin February 1993 and has served in various legal positions includingGeneral Counsel of the Company's independent power affiliates.From 1990 to 1993, Mr. Anderson was a corporate attorney with Fraser,Stryker in Omaha, NE. Prior to that Mr. Anderson was a principal in thefirm Anderson and Anderson.

KEITH D. HARTJE, 54, Senior VicePresident and Chief Administrative Officer. Mr. Hartje has been withMidAmerican Energy and its predecessor companies since 1973. In thattime, he has held a number of positions, including General Counsel andCorporate Secretary, District Vice President for southwest Iowaoperations, and Vice President, Corporate Communications.

WARRENE. BUFFETT, 73, Director. Mr. Buffett has been a director of MEHC sinceMarch 2000. He is Chairman of the Board and Chief Executive Office ofBerkshire Hathaway Inc. Mr. Buffett is a Director of the Coca-ColaCompany, the Gillette Company and The Washington Post Company.

101

----

WALTER SCOTT, JR., 72, Director. Mr.Scott has been a director of MEHC since June 1991. Mr. Scott was theChairman and Chief Executive Officer of MEHC from January 8, 1992 untilApril 19, 1993. For more than the past five years, he has been Chairmanof the Board of Directors of Level 3 Communications, Inc., a successorto certain businesses of Peter Kiewit & Sons', Inc. Mr. Scottis a director of Peter Kiewit & Sons', Inc., BerkshireHathaway Inc., Burlington Resources, Inc., ConAgra, Inc., ValmontIndustries, Inc., Kiewit Materials Co., Commonwealth TelephoneEnterprises, Inc. and RCN Corporation. Mr. Scott is the father of W.David Scott.

MARC D. HAMBURG, 54, Director. Mr. Hamburg has beena director of MEHC since March 2000. He has served as Vice President– Chief Financial Officer of Berkshire Hathaway Inc. sinceOctober 1, 1992 and Treasurer since June 1, 1987, his date ofemployment with Berkshire Hathaway Inc.

W. DAVID SCOTT, 42,Director. Mr. Scott has been a director of MEHC since March 2000. Mr.Scott formed Magnum Resources, Inc., a commercial real estateinvestment and management company, in October 1994 and has served asits President and Chief Executive Officer since its inception. Beforeforming 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 adirector of MEHC since 1983. Mr. Aronson founded EDACO, Inc., a privateventure 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 ofthe International Department of Salomon Brothers Inc. from 1973 to1979. Mr. Aronson served during 1962-1968 as Vice Presidentconsecutively in the International Departments of First National Bankof Chicago and Republic National Bank of New York. He founded theInternational Department of Salomon Brothers and Hutzler in 1968.

JOHN K. BOYER, 59, Director. Mr. Boyer has been a director of MEHCsince March 2000. He is a partner with Fraser, Stryker, Meusey, Olson,Boyer & Bloch, P.C. where he has practiced from 1973 to presentwith emphasis on corporate, commercial, federal, state, and localtaxation.

STANLEY J. BRIGHT, 63, Director. Mr. Bright wasChairman and Chief Executive Officer of MidAmerican Energy from July 1,1995 until March 1999. Mr. Bright joined Iowa-Illinois Gas and ElectricCompany (a predecessor of MidAmerican Energy) as Vice President andChief Financial Officer in 1986, became a director in 1987, Presidentand Chief Operating Officer in 1990, and Chairman and Chief ExecutiveOfficer in 1991.

RICHARD R. JAROS, 51, Director. Mr. Jaros hasbeen a director of MEHC since March 1991. Mr. Jaros served as Presidentand Chief Operating Officer of MEHC from January 8, 1992 to April 19,1993 and as Chairman of the Board from April 19, 1993 to May 1994.Until July 1997, Mr. Jaros was Executive Vice President and ChiefFinancial Officer of Peter Kiewit & Sons', Inc. and Presidentof Kiewit Diversified Group, Inc., which is now Level 3 Communications,Inc. Mr. Jaros serves as director of Commonwealth TelephoneEnterprises, Inc., RCN Corporation and Level 3 Communications, Inc.

Audit Committee Members and Financial Experts

The auditcommittee of the Board of Directors is comprised of Messrs. Marc D.Hamburg and Richard R. Jaros. The Board of Directors has determinedthat Messrs. Hamburg and Jaros qualify as "audit committeefinancial experts", as defined by Securities and ExchangeCommission Rules, based on their education, experience and background.Mr. Jaros is independent as that term is used in Item 7(d) (3) (IV) ofSchedule 14A under the Exchange Act.

Code of Ethics

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

Item 11.    Executive Compensation.

The following tablesets forth the compensation of MEHC's Chief Executive Officer andits four other most highly compensated executive officers who wereemployed as of December 31, 2003, which 

102

----

MEHC refers to as its Named ExecutiveOfficers. Information is provided regarding its Named ExecutiveOfficers for the last three fiscal years during which they were itsexecutive officers, if applicable.

|                            |  |                 |        |           |  |          |         |                         |  |                 |           |        |  |        |            |        |  |        |        |        |  |  |
|----------------------------|--|-----------------|--------|-----------|--|----------|---------|-------------------------|--|-----------------|-----------|--------|--|--------|------------|--------|--|--------|--------|--------|--|--|
| Nameand PrincipalPositions |  | YearEndedDec.31 |        | Salary(1) |  | Bonus(1) |         | OtherAnnualCompensation |  | AllOtherComp(2) |
| David L.Sokol              |  |            | 2003   |      |  | $        | 800,000 |                    |  | $               | 2,750,000 |   |  | $      | —    |   |  | $      | 7,960  |   |
| Chairmanand                |  |            | 2002   |      |  |     | 800,000 |                    |  |            | 2,750,000 |   |  |   | 27,122,550 |   |  |   | 7,960  |   |
| ChiefExecutiveOfficer      |  |            | 2001   |      |  |     | 750,000 |                    |  |            | 2,400,000 |   |  |   | —    |   |  |   | 33,033 |   |
|                       |  |            |   |      |  |     |    |                    |  |            |      |   |  |   |       |   |  |   |   |   |
| GregoryE.Abel              |  |            | 2003   |      |  |     | 669,011 |                    |  |            | 2,200,000 |   |  |   | —    |   |  |   | 7,690  |   |
| Presidentand               |  |            | 2002   |      |  |     | 540,000 |                    |  |            | 2,200,000 |   |  |   | —    |   |  |   | 7,636  |   |
| ChiefOperatingOfficer      |  |            | 2001   |      |  |     | 520,000 |                    |  |            | 1,150,000 |   |  |   | —    |   |  |   | 23,657 |   |
|                       |  |            |   |      |  |     |    |                    |  |            |      |   |  |   |       |   |  |   |   |   |
| PatrickJ.Goodman           |  |            | 2003   |      |  |     | 273,570 |                    |  |            | 285,000   |   |  |   | —    |   |  |   | 7,392  |   |
| SeniorVice Presidentand    |  |            | 2002   |      |  |     | 248,000 |                    |  |            | 365,000   |   |  |   | 209,560    |   |  |   | 7,353  |   |
| ChiefFinancialOfficer      |  |            | 2001   |      |  |     | 240,000 |                    |  |            | 260,000   |   |  |   | —    |   |  |   | 13,527 |   |
|                       |  |            |   |      |  |     |    |                    |  |            |      |   |  |   |       |   |  |   |   |   |
| DouglasL.Anderson          |  |            | 2003   |      |  |     | 270,711 |                    |  |            | 240,000   |   |  |   | —    |   |  |   | 7,150  |   |
| SeniorVice Presidentand    |  |            | 2002   |      |  |     | 200,000 |                    |  |            | 325,000   |   |  |   | —    |   |  |   | 7,150  |   |
| GeneralCounsel             |  |            | 2001   |      |  |     | 154,427 |                    |  |            | 200,000   |   |  |   | —    |   |  |   | 6,630  |   |
|                       |  |            |   |      |  |     |    |                    |  |            |      |   |  |   |       |   |  |   |   |   |
| KeithD.Hartje              |  |            | 2003   |      |  |     | 180,000 |                    |  |            | 65,000    |   |  |   | —    |   |  |   | 7,796  |   |
| SeniorVice Presidentand    |  |            | 2002   |      |  |     | 180,000 |                    |  |            | 65,000    |   |  |   | —    |   |  |   | 7,796  |   |
| ChiefAdministrativeOfficer |  |            | 2001   |      |  |     | 180,000 |                    |  |            | 60,000    |   |  |   | —    |   |  |   | 6,630  |   |
|                            |

|  |
|--|
|  |  |
|  |

| (1) | Includesamounts voluntarily deferred by the executive, if applicable. |
|-----|-----------------------------------------------------------------------|

| (2) | Consists of 401(k) Plan contributionsfor 2003 for Messrs. Sokol, Abel, Goodman and Anderson of $7,150, andMr. Hartje of $7,796. To offset its obligations under theCompany's Executive Split Dollar Plan for executives whoseretirement benefit cannot be fully funded through the Company'sBase Retirement Plan for Salaried Employees, the Company has agreed topay the premiums for policies of split dollar life insurance on thelives of such executives. No premiums were paid in 2003 for Mr. Sokol,Mr. Abel, or Mr. Goodman. Included are the insurance premiums in thefollowing amounts paid by the Company with respect to the term lifeinsurance portion of premiums paid in 2003 for Mr. Sokol of $810, forMr. Abel of $540 and for Mr. Goodman of $242. |
|-----|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

Pursuant toMEHC's Executive Incremental Profit Sharing Plan, Messrs. Sokoland Abel are each eligible to receive a one-time profit sharing awardof $11.25 million, $18.75 million or $37.5 million based upon achievingspecified adjusted diluted earnings per share targets for any calendaryear from 2003 through 2007 and continued employment during suchtime.

Option Grants in Last Fiscal Year

MEHC did notgrant any options during 2003.

103

----

Aggregated Option Exercises In LastFiscal Year And Fiscal Year End Option Values

The followingtable sets forth the option exercises and the number of securitiesunderlying exercisable and unexercisable options held by each of itsNamed Executive Officers at December 31, 2003.

|                   |  |                             |         |               |  |                                       |         |                                                 |  |             |           |               |  |        |         |        |  |        |         |        |  |        |         |        |  |  |
|-------------------|--|-----------------------------|---------|---------------|--|---------------------------------------|---------|-------------------------------------------------|--|-------------|-----------|---------------|--|--------|---------|--------|--|--------|---------|--------|--|--------|---------|--------|--|--|
|              |  |                        |         |          |  | UnderlyingUnexercisedOptions Held (#) |         | Value ofUnexercisedIn-the-money Options ($) (1) |
| Name              |  | SharesAcquiredonExercise(#) |         | ValueRealized |  | Exercisable                           |         | Unexercisable                                   |  | Exercisable |           | Unexercisable |
| DavidSokol        |  |                        | — |          |  |                                  | — |                                            |  |        | 1,399,277 |          |  |   | — |   |  |   | N/A     |   |  |   | N/A     |   |
| GregoryE.Abel     |  |                        | — |          |  |                                  | — |                                            |  |        | 649,052   |          |  |   | — |   |  |   | N/A     |   |  |   | N/A     |   |
| PatrickJ.Goodman  |  |                        | — |          |  |                                  | — |                                            |  |        | —   |          |  |   | — |   |  |   | — |   |  |   | — |   |
| DouglasL.Anderson |  |                        | — |          |  |                                  | — |                                            |  |        | —   |          |  |   | — |   |  |   | — |   |  |   | — |   |
| KeithD.Hartje     |  |                        |    |          |  |                                  | — |                                            |  |        | —   |          |  |   | — |   |  |   | — |   |  |   | — |   |
|                   |

|  |
|--|
|  |  |
|  |

| (1) | OnMarch 14, 2000, MEHC was acquired by a private investor group. As aprivately held company, MEHC has no publicly traded equity securitiesand, consequently, its management does not believe there is a reliablemethod of computing the fair market value of the stock as of December31, 2003. |
|-----|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

Long-Term Incentive Plans – Awards in LastFiscal Year

|                    |  |                                          |     |                                                    |  |                  |  |              |         |            |  |        |     |        |  |        |     |        |  |  |  |  |
|--------------------|--|------------------------------------------|-----|----------------------------------------------------|--|------------------|--|--------------|---------|------------|--|--------|-----|--------|--|--------|-----|--------|--|--|--|--|
| Name               |  | Numberof Shares,Units or OtherRights (#) |     | Performance orOtherPeriod Until MaturationorPayout |  | Threshold($)(1)  |  | Target($)(1) |         | Maximum($) |
| Patrick J.Goodman  |  |                                     | N/A |                                               |  | December31,2007  |  |         | 412,500 |       |  |   | N/A |   |  |   | N/A |   |
| DouglasL. Anderson |  |                                     | N/A |                                               |  | December 31,2007 |  |         | 390,000 |       |  |   | N/A |   |  |   | N/A |   |
| KeithD. Hartje     |  |                                     | N/A |                                               |  | December 31,2007 |  |         | 163,913 |       |  |   | N/A |   |  |   | N/A |   |
|                    |

|  |
|--|
|  |  |
|  |

| (1) | Theawards shown in the foregoing table are made pursuant to the Long-TermIncentive Partnership Plan ("LTIP"). Theamounts shown are dollar amounts credited to an investment account forthe benefit of the named executive officers and such amounts vestequally over five years (starting with year 2003) with any unvestedbalances forfeited upon termination of employment unless theparticipant retires at or above age 55 with at least 5 years of servicein which case the participant will receive any unvested portion of theaward. Vested balances (including any investment performance profits orlosses thereon) are paid to the participant at the time of termination.Once an award is fully vested, the participant may elect to defer orreceive payment of part or all of the award. Messrs. Sokol and Abel arenot participants in the LTIP. Awards are credited or reduced withannual interest or loss based on a composite of funds or indices.Because the amounts to be paid out may increase or decrease dependingon investment performance, the ultimate benefits are undeterminable andthe payouts do not have a "target" or"maximum" amount. |
|-----|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

Compensationof 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 Committeemeetings. Directors who are employees are not entitled to receive suchfees. All directors are reimbursed for their expenses incurred inattending Board meetings.

Retirement Plans

The Companymaintains a Supplemental Retirement Plan for Designated Officers, whichthe Company refers to as the Supplemental Plan, to provide additionalretirement benefits to designated participants, as determined by theBoard of Directors. Messrs. Sokol, Abel, Goodman and Hartje areparticipants in the Supplemental Plan. The Supplemental Plan providesannual retirement benefits up to sixty-five percent of aparticipant's Total Cash Compensation in effect immediately priorto retirement, subject to a $1 million maximum retirement benefit."Total Cash Compensation" means the highest

104

----

amount payable to a participant as monthlybase salary during the five years immediately prior to retirementmultiplied by 12 plus the average of the participant's last threeyears awards under an annual incentive bonus program and special,additional or non-recurring bonus awards, if any, that are required tobe included in Total Cash Compensation pursuant to aparticipant's employment agreement or approved for inclusion bythe Board. Participants must be credited with five years service inorder to be eligible to receive benefits under the Supplemental Plan.Each of the Company's Named Executive Officers has or will havefive years of credited service with the Company as of their respectivenormal retirement age and will be eligible to receive benefits underthe Supplemental Plan. A participant who elects early retirement isentitled to reduced benefits under the Supplemental Plan, however, inaccordance with their respective employment agreements, Messrs. Sokoland Abel are eligible to receive the maximum retirement benefit at age47. A survivor benefit is payable to a surviving spouse under theSupplemental Plan. Benefits from the Supplemental Plan will be paid outof general corporate funds; however, through a rabbi trust, the Companymaintains life insurance on the participants in amounts expected to besufficient to fund the after-tax cost of the projected benefits.Deferred compensation is considered part of the salary covered by theSupplemental Plan.

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

The MidAmerican Retirement Plan replaced retirement plans ofpredecessor companies that were structured as traditional, definedbenefit plans. Under the MidAmerican Retirement Plan, each participanthas an account, for record keeping purposes only, to which credits areallocated each payroll period based upon a percentage of theparticipant's salary paid in the current pay period. In addition,all balances in the accounts of participants earn a fixed rate ofinterest that is credited annually. The interest rate for a particularyear is based on the constant maturity Treasury yield plus seven-tenthsof one percentage point. At retirement or other termination ofemployment, an amount equal to the vested balance then credited to theaccount is payable to the participant in the form of a lump sum or aform of annuity for the entire benefit under the MidAmerican RetirementPlan.

Part A of the IOR Supplemental Plan provides retirementbenefits up to sixty-five percent of a participant's highestannual salary during the five years prior to retirement reduced by theparticipant's MidAmerican Retirement Plan benefit. The percentageapplied is based on years of accredited service. A participant whoelects early retirement is entitled to reduced benefits under the plan.A survivor benefit is payable to a surviving spouse. Benefits areadjusted annually for inflation. Part B of the IOR Supplemental Planprovides that an additional one hundred-fifty percent of annual salaryis to be paid out to participants at the rate of ten percent per yearover fifteen years, except in the event of a participant's death,in which event the unpaid balance would be paid to theparticipant's beneficiary or estate. Deferred compensation isconsidered part of the salary covered by the IOR SupplementalPlan.

105

----

The table below shows the estimatedaggregate annual benefits payable under the Supplemental Plan and theMidAmerican Retirement Plan. The amounts exclude Social Security andare based on a straight life annuity and retirement at ages 55, 60 and65. Federal law limits the amount of benefits payable to an individualthrough the tax qualified defined benefit and contribution plans, andbenefits exceeding such limitation are payable under the SupplementalPlan.

|                                                               |  |                         |           |        |  |        |           |        |  |        |           |        |  |  |
|---------------------------------------------------------------|--|-------------------------|-----------|--------|--|--------|-----------|--------|--|--------|-----------|--------|--|--|
|                                                          |  | EstimatedAnnual Benefit |
|                                                          |  | Age atRetirement        |
|   TotalCash  Compensationat 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 |   |
| 2,000,000andgreater                                           |  |                    | 1,000,000 |   |  |   | 1,000,000 |   |  |   | 1,000,000 |   |
|                                                               |

EmploymentAgreements

Pursuant to his employment agreement Mr. Sokolserves as Chairman of MEHC's Board of Directors and ChiefExecutive Officer. The employment agreement provides that Mr. Sokol isto receive an annual base salary of not less than $750,000, seniorexecutive employee benefits and annual bonus awards that shall not beless than $675,000. Subject to an annual renewal provision, suchagreement is scheduled to expire on August 21, 2004.

Theemployment agreement provides that MEHC may terminate the employment ofMr. Sokol with cause, in which case MEHC is to pay to him any accruedbut unpaid salary and a bonus of not less than the minimum annualbonus, or due to death, permanent disability or other than for cause,including a change in control, in which case Mr. Sokol is entitled toreceive an amount equal to three times the sum of his annual salarythen in effect and the greater of his minimum annual bonus or hisaverage annual bonus for the two preceding years, as well as threeyears of accelerated option vesting plus continuation of his seniorexecutive employee benefits (or the economic equivalent thereof) forthree years. If Mr. Sokol resigns, MEHC is to pay to him any accruedbut unpaid salary and a bonus of not less than the annual minimumbonus, unless he resigns for good reason in which case he will receivethe same benefits as if he were terminated other than for cause.

In the event Mr. Sokol has relinquished his position as ChiefExecutive Officer and is subsequently terminated as Chairman of theBoard due to death, disability or other than for cause, he is entitledto any accrued but unpaid salary plus an amount equal to the aggregateannual salary that would have been paid to him through the fifthanniversary of the date he commenced his employment solely as Chairmanof the Board, the immediate vesting of all of his options and thecontinuation of his senior executive employee benefits (or the economicequivalent thereof) through this fifth anniversary. If Mr. Sokolrelinquishes his position as Chief Executive Officer but offers toremain employed as the Chairman of the Board, he is to receive aspecial achievement bonus equal to two times the sum of his annualsalary then in effect and the greater of his minimum annual bonus orhis average annual bonus for the two preceding years, as well as twoyears of accelerated option vesting.

Under the terms of separateemployment agreements with MEHC, each of Messrs. Abel and Goodman isentitled to receive two years base salary continuation, payments inrespect of average bonuses for the prior two years and two yearscontinued option vesting in the event MEHC terminates his employmentother than for cause. If such persons were terminated without cause,Messrs. Sokol, Abel and Goodman would currently be entitled to be paidapproximately $10,650,000, $5,750,000 and $1,200,000, respectively,without giving effect to any tax related provisions.

106

----

Item 12.    Security Ownership ofCertain Beneficial Owners and Management and Related StockholderMatters.

The following table sets forth certain informationregarding beneficial ownership of the shares of MEHC's commonstock and certain information with respect to the beneficial ownershipof each director, its Named Executive Officers and all directors andexecutive officers as a group as of January 31, 2004.

|                                                            |  |                                      |           |                      |  |        |         |         |  |  |
|------------------------------------------------------------|--|--------------------------------------|-----------|----------------------|--|--------|---------|---------|--|--|
| Nameand Address of BeneficialOwner(1)                      |  | Number ofSharesBeneficially Owned(2) |           | PercentageofClass(2) |
| CommonStock:                                               |  |                                 |      |                 |  |   |    |    |
| Walter Scott, Jr.(3)                                       |  |                                 | 5,000,000 |                 |  |   | 55.06   | %  |
| David L. Sokol(4)                                          |  |                                 | 1,523,482 |                 |  |   | 14.54   | %  |
| BerkshireHathaway Inc. (5)                                 |  |                                 | 900,942   |                 |  |   | 9.92    | %  |
| Gregory E.Abel(6)                                          |  |                                 | 704,992   |                 |  |   | 7.25    | %  |
| W.David Scott(7)                                           |  |                                 | 624,350   |                 |  |   | 6.88    | %  |
| DouglasL. Anderson                                         |  |                                 | —   |                 |  |   | — |    |
| Edgar D.Aronson                                            |  |                                 | —   |                 |  |   | — |    |
| Stanley J.Bright                                           |  |                                 | —   |                 |  |   | — |    |
| John K.Boyer                                               |  |                                 | —   |                 |  |   | — |    |
| Warren E.Buffett(8)                                        |  |                                 | —   |                 |  |   | — |    |
| PatrickJ. Goodman                                          |  |                                 | —   |                 |  |   | — |    |
| Marc D.Hamburg(8)                                          |  |                                 | —   |                 |  |   | — |    |
| RichardR. Jaros                                            |  |                                 | —   |                 |  |   | — |    |
| Keith D.Hartje                                             |  |                                 | —   |                 |  |   | — |    |
| All directorsand executive officers as a group (14persons) |  |                                 | 8,753,766 |                 |  |   | 77.40   | %  |
|                                                            |

|  |
|--|
|  |  |
|  |

| (1) | Unlessotherwise indicated, each address is c/o MEHC at 666 Grand Avenue,29th Floor, Des Moines, Iowa 50309. |
|-----|-------------------------------------------------------------------------------------------------------------|

| (2) | Includes shares which the listedbeneficial owner is deemed to have the right to acquire beneficialownership under Rule 13d-3(d) under the Securities Exchange Act,including, among other things, shares which the listed beneficial ownerhas the right to acquire within 60 days. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (3) | Excludes 3 million shares held byfamily members and family controlled trusts and corporations("Scott Family Interests") as to which Mr.Scott disclaims beneficial ownership. Such beneficial owner'saddress is 1000 Kiewit Plaza, Omaha, Nebraska 68131. |
|-----|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

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

| (5) | Such beneficial owner's addressis 1440 Kiewit Plaza, Omaha, Nebraska 68131. |
|-----|-----------------------------------------------------------------------------|

| (6) | Includes options to purchase 649,052shares of common stock which are exercisable within 60 days. Excludes10,041 shares reserved for issuance pursuant to a deferred compensationplan. |
|-----|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (7) | Includes shares held bytrusts for the benefit of or controlled by W. David Scott. Suchbeneficial owner's address is 11422 Miracle Hills Drive, Suite400, Omaha, Nebraska68154. |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (8) | Excludes 900,942 sharesof common stock held by Berkshire Hathaway Inc. of which beneficialownership of such shares is disclaimed. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------|

The terms ofMEHC's Zero Coupon Convertible Preferred Stock held by BerkshireHathaway entitle the holder thereof to elect two members of its Boardof Directors. The Zero Coupon Convertible Preferred Stock does not voteas to the election of any other members of MEHC's Board ofDirectors. Mr. Sokol's employment agreement gives him the rightduring the term of his employment to serve as a member of the Board ofDirectors and to designate two additional directors.

Pursuant toa shareholders agreement, following March 14, 2003, Walter Scott, Jr.or any of the Scott Family Interests are able to require BerkshireHathaway to purchase, for an agreed value or an appraised value, any orall of Walter Scott, Jr.'s and the Scott Family Interests'shares of MEHC's common stock, 

107

----

provided that Berkshire Hathaway is then apurchaser of a type which is able to consummate such a purchase withoutcausing it or any of its affiliates or MEHC or any of its subsidiariesto become subject to regulation as a registered holding company or asubsidiary of a registered holding company under PUHCA. BerkshireHathaway is not currently such a purchaser. The consummation of such atransaction could result in a change in control with respect toMEHC.

MEHC's Amended and Restated Articles ofIncorporation provide that each share of the Zero Coupon ConvertiblePreferred Stock is convertible at the option of the holder thereof intoone conversion unit, which is one share of its common stock subject tocertain adjustments as described in its articles, upon the occurrenceof a Conversion Event. A "Conversion Event"includes (1) any conversion of Zero Coupon Convertible Preferred Stockthat would not cause the holder of the shares of common stock issuedupon conversion (or any affiliate of such holder) or the Company tobecome subject to regulation as a registered holding company or as asubsidiary of a registered holding company under PUHCA either as aresult of the repeal or amendment of PUHCA, the number of sharesinvolved or the identity of the holder of such shares and (2) a CompanySale. A "Company Sale" includes MEHC'sinvoluntary or voluntary liquidation, dissolution, recapitalization,winding-up or termination and mergers, consolidations or sale of all orsubstantially all of its assets. The conversion by Berkshire Hathawayof its shares of Zero Coupon Convertible Preferred Stock intoMEHC's common stock could result in a change in control withrespect to beneficial ownership of its voting securities as calculatedpursuant to Rule 13d-3(d) under the Securities Exchange Act.

Item 13.    Certain Relationships and Related Transactions.

Under a subscription agreement with MEHC, Berkshire Hathaway hasagreed to purchase, under certain circumstances, additional 11%trust issued mandatorily redeemable preferred securities in the eventthat certain outstanding trust preferred securities of MEHC which wereoutstanding prior to the closing of its acquisition by a privateinvestor group on March 14, 2000 are tendered for conversion to cash bythe current holders.

MEHC provided a guarantee in favor of athird party lender in connection with a $1,663,998.75 loan from suchlender to its President, Gregory E. Abel, in March 2000. The loanmatures on April 1, 2010. The proceeds of this loan were used by Mr.Abel to purchase 47,475 shares of MEHC's common stock. Suchcommon stock (together with 8,465 additional shares of common stockowned by Mr. Abel) also secures the loan. The entire original principalamount of the loan and the guarantee remain presently outstanding.

In order to finance its acquisition of Northern Natural Gas, onAugust 16, 2002, MEHC sold to Berkshire Hathaway and three of itsconsolidated subsidiaries $950.0 million in aggregate principal amountof the 11% mandatorily redeemable trust issued preferredsecurities Series A, of its subsidiary trust, MidAmerican Capital TrustII, due August 31, 2012. The transaction was a private placementpursuant to Section 4(1) of the Securities Act and did not involve anyunderwriters, underwriting discounts or commissions. Scheduledprincipal payments began in August 2003. Messrs. Warren E. Buffett andWalter Scott, Jr. are members of the Board of Directors of BerkshireHathaway. Messrs. Buffett and Marc D. Hamburg are executive officers ofBerkshire Hathaway.

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

On January 6, 2004,MEHC purchased shares of common stock from Mr. Sokol for an aggregateprice of $20.0 million.

Compensation Committee Interlocks andInsider Participation

The compensation committee of the Boardof Directors is comprised of Messrs. Warren E. Buffett and WalterScott, Jr.  Mr. Walter Scott, Jr. is a former officer of theCompany. See "Certain Relationships and RelatedTransactions."

108

----

Item 14.    Principal Accountant Feesand Services.

Aggregate fees billed to the Company as aconsolidated entity for the fiscal years ending December 31, 2003 and2002 by the Company's principal accounting firm, Deloitte &Touche LLP and their respective affiliates (collectively,"Deloitte"), are set forth below. The auditcommittee has considered whether the provision of the non-auditservices described below is compatible with maintaining the principalaccountant's independence.

|                           |  |                        |         |        |  |        |         |        |  |  |
|---------------------------|--|------------------------|---------|--------|--|--------|---------|--------|--|--|
|                      |  | YearEnded December 31, |
|                      |  | 2003                   |         | 2002   |
|                      |  | (inmillions)           |
| Audit Fees(1)             |  | $                      | 2.6     |   |  | $      | 2.2     |   |
| Audit-RelatedFees (2)     |  |                   | 0.3     |   |  |   | 0.4     |   |
| Tax Fees(3)               |  |                   | 0.9     |   |  |   | 1.3     |   |
| All OtherFees(4)          |  |                   | — |   |  |   | — |   |
| Totalaggregate feesbilled |  | $                      | 3.8     |   |  | $      | 3.9     |   |
|                           |

|  |
|--|
|  |  |
|  |

| (1) | Includesthe aggregate fees billed for each of the last two fiscal years forprofessional services rendered by Deloitte for the audit of theCompany's financial statements and review of financial statementsincluded in the Company's Form 10-K or services that are normallyprovided by Deloitte in connection with statutory and regulatoryfilings or engagements for those fiscalyears. |
|-----|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (2) | Includes the aggregatefees billed for each of the last two fiscal years for assurance andrelated services by Deloitte that are reasonably related to theperformance of the audit or review of the registrant's financialstatements. Services included in this category include audits ofbenefit plans, due diligence for possible acquisitions and consultationpertaining to new and proposed accounting and regulatoryrules. |
|-----|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (3) | Includes the aggregatefees billed for each of the last two fiscal years for professionalservices rendered by Deloitte for tax compliance, tax advice, and taxplanning. |
|-----|------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (4) | Includes theaggregate fees billed for each of the last two fiscal years forproducts and services provided by Deloitte, other than the servicesreported as "Audit Fees","Audit-Related Fees", or "TaxFees". |
|-----|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

The audit committee reviewed thenon-audit services rendered by Deloitte in and for fiscal 2003 as setforth in the above table and concluded that such services werecompatible with maintaining the auditors' independence. Under theSarbanes-Oxley Act of 2002, all audit and non-audit services performedby the Company's independent accountants must now be approved inadvance by the audit committee to assure that such services do notimpair the accountants' independence from the Company.Accordingly, the audit committee has adopted an Audit and Non-AuditServices Pre-Approval Policy (the "Policy")which sets forth the procedures and the conditions pursuant to whichservices to be performed by the independent accountants are to bepre-approved. Pursuant to the Policy, certain services described indetail in the Policy may be pre-approved on an annual basis togetherwith pre-approved maximum fee levels for such services. The serviceseligible for annual pre-approval consist of services that would beincluded under the categories of Audit Fees, Audit-Related Fees and TaxFees. If not pre-approved on an annual basis, proposed services mustotherwise be separately approved prior to being performed by theindependent auditors. In addition, any services that receive annualpre-approval but exceed the pre-approved maximum fee level also willrequire separate approval by the audit committee prior to beingperformed. The audit committee may delegate authority to pre-approveaudit and non-audit services to any member of the audit committee, butmay not delegate such authority tomanagement.

109

----

PART IV

Item15.    Exhibits, Financial Statement Schedules and Reports on Form8-K

|           |                                   |
|-----------|-----------------------------------|
| (a)  | Financial Statements andSchedules |

|           |                     |
|-----------|---------------------|
| (i)  | FinancialStatements |

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

|            |                              |
|------------|------------------------------|
| (ii)  | FinancialStatement Schedules |

See Schedule I on page 111. SeeSchedule II on page 114. Schedules not listed above have beenomitted because they are either not applicable, not required or theinformation required to be set forth therein is included in theconsolidated financial statements or notes thereto.

|             |          |
|-------------|----------|
| (iii)  | Exhibits |

See Item15 (c) below.

|           |                     |
|-----------|---------------------|
| (b)  | Reports on Form 8-K |

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

|              |                                                            |
|--------------|------------------------------------------------------------|
| •  | MEHCfiled a Current Report on Form 8-K on October 15,2003. |

|              |                                                             |
|--------------|-------------------------------------------------------------|
| •  | MEHC filed a CurrentReport on Form 8-K on October 17, 2003. |

|              |                                                                      |
|--------------|----------------------------------------------------------------------|
| •  | MEHC filed an amended CurrentReport on Form 8-K on October 21, 2003. |

|           |          |
|-----------|----------|
| (c)  | Exhibits |

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

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

Not applicable.

110

----

| MidAmerican Energy HoldingsCompany                                             | Schedule I |
|--------------------------------------------------------------------------------|------------|
| Parent Company Only                                                            |
| CondensedBalance Sheets As of December 31, 2003 and 2002 (Amounts inthousands) |

|                                                                                                                                              |  |        |           |         |  |        |           |         |  |  |
|----------------------------------------------------------------------------------------------------------------------------------------------|--|--------|-----------|---------|--|--------|-----------|---------|--|--|
|                                                                                                                                         |  | 2003   |           | 2002    |
| **ASSETS**                                                                                                                                   |
| Currentassets —Cash and cashequivalents                                                                                                |  | $      | 328,750   |    |  | $      | 320,629   |    |
| Investmentsin and advances to subsidiaries and jointventures                                                                                 |  |   | 5,728,125 |    |  |   | 5,264,786 |    |
| Equipment,net                                                                                                                                |  |   | 15,388    |    |  |   | 15,984    |    |
| Goodwill                                                                                                                                     |  |   | 1,370,241 |    |  |   | 1,381,009 |    |
| Deferredcharges and otherassets                                                                                                              |  |   | 180,331   |    |  |   | 150,056   |    |
| **Totalassets**                                                                                                                              |  | $      | 7,622,835 |    |  | $      | 7,132,464 |    |
| **LIABILITIESAND STOCKHOLDERS' EQUITY**                                                                                                      |
| Currentliabilities:Accounts payable and other accruedliabilities                                                                             |  | $      | 49,144    |    |  | $      | 94,389    |    |
| Currentportion of long-termdebt                                                                                                              |  |   | —   |    |  |   | 215,000   |    |
| Currentportion of subordinateddebt                                                                                                           |  |   | 100,000   |    |  |   | —   |    |
| Totalcurrent liabilities..                                                                                                                   |  |   | 149,144   |    |  |   | 309,389   |    |
| Non-currentliabilities                                                                                                                       |  |   | 31,298    |    |  |   | 11,885    |    |
| Notespayable —affiliate                                                                                                                |  |   | 86,045    |    |  |   | 94,795    |    |
| Seniordebt                                                                                                                                   |  |   | 2,777,878 |    |  |   | 2,323,387 |    |
| Subordinateddebt                                                                                                                             |  |   | 1,772,146 |    |  |   | —   |    |
| Totalliabilities                                                                                                                             |  |   | 4,816,511 |    |  |   | 2,739,456 |    |
| Deferredincome                                                                                                                               |  |   | 32,916    |    |  |   | 35,313    |    |
| Minorityinterest                                                                                                                             |  |   | 1,963     |    |  |   | —   |    |
| Company-obligatedmandatorily redeemablepreferred securities of subsidiarytrusts                                                              |  |   | —   |    |  |   | 2,063,412 |    |
| Stockholders'equity:                                                                                                                         |  |
| Zero coupon convertiblepreferred stock — authorized 50,000 shares, no par value; 41,263shares outstanding at December 31, 2003 and2002 |  |   | —   |    |  |   | —   |    |
| Common stock— authorized 60,000 shares, no par value; 9,281 sharesoutstanding at December 31, 2003 and2002                             |  |   | —   |    |  |   | —   |    |
| Additional paidincapital                                                                                                                     |  |   | 1,957,277 |    |  |   | 1,956,509 |    |
| Retainedearnings                                                                                                                             |  |   | 999,627   |    |  |   | 584,009   |    |
| Accumulatedother comprehensive loss,net                                                                                                      |  |   | (185,459  | )  |  |   | (246,235  | )  |
| Totalstockholders'equity                                                                                                                     |  |   | 2,771,445 |    |  |   | 2,294,283 |    |
| **Totalliabilities and stockholders'equity**                                                                                                 |  | $      | 7,622,835 |    |  | $      | 7,132,464 |    |
|                                                                                                                                              |

Thenotes to the consolidated MEHC financial statements are an integralpart of this financial statement schedule.

111

----

| MidAmerican Energy HoldingsCompany                                                                   | Schedule I |
|------------------------------------------------------------------------------------------------------|------------|
| Parent Company Only (continued)                                                                      |
| Condensed Statements of Operations For the three years endedDecember 31, 2003 (Amounts in thousands) |

|                                                                           |  |        |           |        |  |        |         |        |  |        |         |         |  |  |
|---------------------------------------------------------------------------|--|--------|-----------|--------|--|--------|---------|--------|--|--------|---------|---------|--|--|
|                                                                      |  | 2003   |           | 2002   |  | 2001   |
| **Revenue:**                                                              |  |
| Equityin undistributed earnings of subsidiary companies and jointventures |  | $      | 785,072   |   |  | $      | 477,588 |   |  | $      | 608,896 |    |
| Dividendsand distributions from subsidiary companies and jointventures    |  |   | 318,665   |   |  |   | 351,847 |   |  |   | 87,625  |    |
| Interestand otherincome                                                   |  |   | 19,808    |   |  |   | 1,286   |   |  |   | 2,248   |    |
| Totalrevenue                                                              |  |   | 1,123,545 |   |  |   | 830,721 |   |  |   | 698,769 |    |
| **Costsand expenses:**                                                    |  |
| General andadministration                                                 |  |   | 34,517    |   |  |   | 29,368  |   |  |   | 41,078  |    |
| Depreciationandamortization                                               |  |   | 710       |   |  |   | 815     |   |  |   | 31,537  |    |
| Interest,net of capitalizedinterest                                       |  |   | 251,578   |   |  |   | 173,240 |   |  |   | 148,680 |    |
| Totalcosts and expenses..                                                 |  |   | 286,805   |   |  |   | 203,423 |   |  |   | 221,295 |    |
| **Incomebefore provision for incometaxes**                                |  |   | 836,740   |   |  |   | 627,298 |   |  |   | 477,474 |    |
| Provisionfor incometaxes                                                  |  |   | 250,971   |   |  |   | 99,588  |   |  |   | 250,064 |    |
| **Incomebefore minorityinterest**                                         |  |   | 585,769   |   |  |   | 527,710 |   |  |   | 227,410 |    |
| Minorityinterest and preferreddividends                                   |  |   | 170,151   |   |  |   | 147,667 |   |  |   | 80,137  |    |
| **Incomebefore and cumulative effect of change in accountingprinciple**   |  |   | 415,618   |   |  |   | 380,043 |   |  |   | 147,273 |    |
| Cumulativeeffect of change in accounting principle, net oftax             |  |   | —   |   |  |   | — |   |  |   | (4,604  | )  |
| **Netincome available to commonstockholders**                             |  | $      | 415,618   |   |  | $      | 380,043 |   |  | $      | 142,669 |    |
|                                                                           |

Thenotes to the consolidated MEHC financial statements are an integralpart of this financial statement schedule.

112

----

| MidAmerican Energy HoldingsCompany                                                                   | Schedule I |
|------------------------------------------------------------------------------------------------------|------------|
| Parent Company Only (continued)                                                                      |
| Condensed Statements of Cash Flows For the three years endedDecember 31, 2003 (Amounts in thousands) |

|                                                                                     |  |        |          |         |  |        |            |         |  |        |          |         |  |  |
|-------------------------------------------------------------------------------------|--|--------|----------|---------|--|--------|------------|---------|--|--------|----------|---------|--|--|
|                                                                                |  | 2003   |          | 2002    |  | 2001   |
| **Cashflows from operatingactivities**                                              |  | $      | (260,271 | )  |  | $      | (188,300   | )  |  | $      | (272,906 | )  |
| **Cashflows from investing activities:**                                            |  |
| Decrease(increase) in advances to and investments in subsidiaries and jointventures |  |   | 205,206  |    |  |   | (1,692,742 | )  |  |   | 204,118  |    |
| Other,net                                                                           |  |   | 30,995   |    |  |   | 10,307     |    |  |   | (5,297   | )  |
| Netcash flows from investingactivities                                              |  |   | 236,201  |    |  |   | (1,682,435 | )  |  |   | 198,821  |    |
| **Cashflows from financing activities:**                                            |  |
| Proceedsfrom issuance of common and preferredstock                                  |  |   | —  |    |  |   | 402,000    |    |  |   | —  |    |
| Proceedsfrom issuance of trust preferredsecurities                                  |  |   | —  |    |  |   | 1,273,000  |    |  |   | —  |    |
| Repaymentof subordinateddebt                                                        |  |   | (198,958 | )  |  |   | —    |    |  |   | —  |    |
| Proceedsfrom issuances of seniordebt                                                |  |   | 449,295  |    |  |   | 700,000    |    |  |   | —  |    |
| Repaymentsof seniordebt                                                             |  |   | (215,000 | )  |  |   | —    |    |  |   | (32      | )  |
| Net(repayment of) proceeds from corporate revolving creditfacility                  |  |   | —  |    |  |   | (153,500   | )  |  |   | 68,500   |    |
| Other                                                                               |  |   | (3,146   | )  |  |   | (32,660    | )  |  |   | (82      | )  |
| Netcash flows from financingactivities                                              |  |   | 32,191   |    |  |   | 2,188,840  |    |  |   | 68,386   |    |
| **Netchange in cash and cashequivalents**                                           |  |   | 8,121    |    |  |   | 318,105    |    |  |   | (5,699   | )  |
| **Cashand cash equivalents at beginning ofyear**                                    |  |   | 320,629  |    |  |   | 2,524      |    |  |   | 8,223    |    |
| **Cashand cash equivalents at end ofyear**                                          |  | $      | 328,750  |    |  | $      | 320,629    |    |  | $      | 2,524    |    |
| **Supplementaldisclosures:**                                                        |  |
| Interest paid, net ofinterestcapitalized                                            |  | $      | 219,910  |    |  | $      | 164,267    |    |  | $      | 148,999  |    |
| Incometaxespaid                                                                     |  | $      | 9,911    |    |  | $      | 101,225    |    |  | $      | 133,139  |    |
|                                                                                     |

Thenotes to the consolidated MEHC financial statements are an integralpart of this financial statement schedule.

113

----

Schedule II

MIDAMERICANENERGY HOLDINGS COMPANY CONSOLIDATED VALUATION AND QUALIFYINGACCOUNTS FOR THE THREE YEARS ENDED DECEMBER 31, 2002(Amounts in thousands)

|                                              |  |                                  |        |                        |  |                   |        |                            |  |   |         |        |  |   |         |        |  |   |         |         |  |   |        |        |  |  |
|----------------------------------------------|--|----------------------------------|--------|------------------------|--|-------------------|--------|----------------------------|--|---|---------|--------|--|---|---------|--------|--|---|---------|---------|--|---|--------|--------|--|--|
| ColumnADescription                           |  | ColumnBBalance atBeginningofYear |        | ColumnCAdditions       |  | ColumnDDeductions |        | Column EBalanceatEndofYear |
| ChargedtoIncome                              |  | OtherAccounts                    |        | AcquisitionReserves(2) |  |
| Reserves Deducted From Assets                |  |
| To Which TheyApply:                          |  |
| Reserve foruncollectible accountsreceivable: |  |
| Year ended2003                               |  | $                                | 39,742 |                   |  | $                 | 13,620 |                       |  | $ | — |   |  | $ | — |   |  | $ | (27,358 | )  |  | $ | 26,004 |   |
| Yearended 2002                               |  | $                                | 7,319  |                   |  | $                 | 27,782 |                       |  | $ | — |   |  | $ | 10,142  |   |  | $ | (5,501  | )  |  | $ | 39,742 |   |
| Yearended 2001                               |  | $                                | 32,685 |                   |  | $                 | 17,061 |                       |  | $ | — |   |  | $ | — |   |  | $ | (42,427 | )  |  | $ | 7,319  |   |
| ReservesNot Deducted From Assets(1):         |  |
| Year ended2003                               |  | $                                | 10,981 |                   |  | $                 | 10,527 |                       |  | $ | — |   |  | $ | — |   |  | $ | (4,091  | )  |  | $ | 17,417 |   |
| Yearended 2002                               |  | $                                | 13,631 |                   |  | $                 | 2,798  |                       |  | $ | 247     |   |  | $ | — |   |  | $ | (5,695  | )  |  | $ | 10,981 |   |
| Yearended 2001                               |  | $                                | 25,063 |                   |  | $                 | 5,046  |                       |  | $ | — |   |  | $ | — |   |  | $ | (16,478 | )  |  | $ | 13,631 |   |
|                                              |

Thenotes to the consolidated MEHC financial statements are an integralpart of this financial statementschedule.

|           |                                                                                                                                                                |
|-----------|----------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (1)  | Reserves not deductedfrom assets include estimated liabilities for losses retained by MEHCfor workers compensation, public liability and property damageclaims |

|           |                                                                                                                       |
|-----------|-----------------------------------------------------------------------------------------------------------------------|
| (2)  | Acquisition reservesrepresent the reserves recorded at Kern River and Northern Natural Gasat the date of acquisition. |

114

----

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of theSecurities Exchange Act of 1934, the Registrant has duly caused thisreport to be signed on its behalf by the undersigned thereunto dulyauthorized, in the City of Des Moines, State of Iowa, on this3rd day of March 2004.

|  | MIDAMERICANENERGY HOLDINGS COMPANY |
|--|------------------------------------|

|  | /s/ David L.Sokol* |
|--|--------------------|

|  |
|--|
|  |  |  |
|  |

|  | DavidL. Sokol Chairman of the Board and Chief Executive Officer |
|--|-----------------------------------------------------------------|

Pursuant to the requirements of the Securities Exchange Actof 1934, this report has been signed below by the following persons onbehalf of the Registrant and in the capacities and on the datesindicated.

|                                                                                                                        |  |               |  |  |  |  |
|------------------------------------------------------------------------------------------------------------------------|--|---------------|--|--|--|--|
| Signature                                                                                                              |  | Date          |
| /s/ David L.Sokol*__________________________ David L. Sokol Chairman ofthe Board, Chief Executive Officer, andDirector |  | March 3, 2004 |
| /s/ Gregory E. Abel*__________________________GregoryE. Abel President, Chief Operating Officer and Director           |  | March 3, 2004 |
| /s/ Patrick J. Goodman*__________________________Patrick J. Goodman Senior VicePresident and Chief Financial Officer   |  | March 3,2004  |
| /s/ Edgar D. Aronson*__________________________Edgar D. Aronson Director                                               |  | March 3, 2004 |
| /s/ Stanley J. Bright*__________________________Stanley J. Bright Director                                             |  | March 3, 2004 |
| /s/ Walter Scott, Jr.*__________________________Walter Scott, Jr. Director                                             |  | March 3, 2004 |
| /s/ Marc D. Hamburg*__________________________Marc D. Hamburg Director                                                 |  | March 3, 2004 |
| /s/ Warren E. Buffett*__________________________Warren E. Buffett Director                                             |  | March 3, 2004 |
|                                                                                                                        |

115

----

|                                                                          |  |               |  |  |  |  |
|--------------------------------------------------------------------------|--|---------------|--|--|--|--|
| Signature                                                                |  | Date          |
| /s/ John K. Boyer*__________________________John K. Boyer Director       |  | March3, 2004  |
| /s/ W. David Scott*__________________________W. David Scott Director     |  | March3, 2004  |
| /s/ Richard R. Jaros*__________________________Richard R. Jaros Director |  | March 3, 2004 |
| *By: /s/ Douglas L. Anderson______________________                       |  | March 3,2004  |
| DouglasL. Anderson Attorney-in-Fact                                      |  |
|                                                                          |

116

----

EXHIBITINDEX

|            |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  |  |  |  |
|------------|--|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--|--|--|--|
| ExhibitNo. |  |
| 3.1        |  | Amendedand Restated Articles of Incorporation of MEHC effective March 6, 2002(incorporated by reference to Exhibit 3.3 to MEHC's Annual Reporton Form 10-K for the year ended December 31,2001).                                                                                                                                                                                                                                                                                                                                         |
| 3.2        |  | Bylaws of MEHC (incorporated byreference to Exhibit 3.2 to MEHC's Annual Report on Form 10-K/Afor the year ended December 31, 1999).                                                                                                                                                                                                                                                                                                                                                                                                     |
| 4.1        |  | Indenture, dated as of October 4, 2002, by andbetween 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 RegistrationStatement No. 333-101699 dated December 6, 2002).                                                                                                                                                                                                                                                   |
| 4.2        |  | First Supplemental Indenture, dated as of October4, 2002, by and between MEHC and The Bank of New York, relating to the4.625% Senior Notes due 2007 and the 5.875% Senior Notesdue 2012 (incorporated by reference to Exhibit 4.2 of MEHC'sRegistration Statement No. 333-101699 dated December 6,2002).                                                                                                                                                                                                                                 |
| 4.3        |  | Registration Rights Agreement,dated as of October 1, 2002, by and between MEHC and Credit SuisseFirst Boston (as Representative for the Initial Purchasers)(incorporated by reference to Exhibit 4.3 of MEHC's RegistrationStatement No. 333-101699 dated December  6, 2002).                                                                                                                                                                                                                                                            |
| 4.4        |  | Indenture for the 6 1/4% Convertible JuniorSubordinated 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 AnnualReport on Form 10-K for the year ended December 31, 1995).                                                                                                                                                                                                                                          |
| 4.5        |  | Indenture, dated as of October 15, 1997, amongMEHC and IBJ Schroder Bank & Trust Company, as Trustee(incorporated by reference to Exhibit 4.1 to MEHC's CurrentReport on Form 8-K dated October 23, 1997).                                                                                                                                                                                                                                                                                                                           |
| 4.6        |  | Form of First Supplemental Indenture for the7.63% Senior Notes in the principal amount of $350,000,000 due2007, dated as of October 28, 1997, among MEHC and IBJ Schroder Bank& Trust Company, as Trustee (incorporated by reference to Exhibit4.2 to MEHC's Current Report on Form 8-K dated October 23,1997).                                                                                                                                                                                                                      |
| 4.7        |  | Form of Second SupplementalIndenture for the 6.96% Senior Notes in the principal amount of$215,000,000 due 2003, 7.23% Senior Notes in the principalamount of $260,000,000 due 2005, 7.52% Senior Notes in theprincipal amount of $450,000,000 due 2008, and 8.48% SeniorNotes in the principal amount of $475,000,000 due 2028, dated as ofSeptember 22, 1998 between MEHC and IBJ Schroder Bank & TrustCompany, as Trustee (incorporated by reference to Exhibit 4.1 toMEHC's Current Report on Form 8-K dated September 17,1998.) |
| 4.8        |  | Form of Third SupplementalIndenture for the 7.52% Senior Notes in the principal amount of$100,000,000 due 2008, dated as of November 13, 1998, between MEHC andIBJ Schroder Bank & Trust Company, as Trustee (incorporated byreference to MEHC's Current Report on Form 8-K dated November 10,1998).                                                                                                                                                                                                                                 |
| 4.9        |  | Indenture, dated as of March 14,2000, among MEHC and the Bank of New York, as Trustee (incorporated byreference to Exhibit 4.9 to MEHC's Annual Report on Form10-K/A for the year ended December 31, 1999).                                                                                                                                                                                                                                                                                                                              |
| 4.10       |  | SubscriptionAgreement, dated as of March 14, 2000, executed by Berkshire HathawayInc. (incorporated by reference to Exhibit 4.10 to MEHC's AnnualReport on Form 10-K/A for the year ended December 31, 1999).                                                                                                                                                                                                                                                                                                                            |
|            |

117

----

|            |  |                                                                                                                                                                                                                                              |  |  |  |  |
|------------|--|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--|--|--|--|
| ExhibitNo. |  |
| 4.11       |  | Indenture, dated as ofMarch 12, 2002, between MEHC and the Bank of New York, as Trustee(incorporated by reference to Exhibit 4.11 to MEHC's AnnualReport on Form 10-K for the year ended December 31, 2001).                                 |
| 4.12       |  | Subscription Agreement, dated as of March 7,2002, executed by Berkshire Hathaway Inc. (incorporated by reference toExhibit 4.12 to MEHC's Annual Report on Form 10-K for the yearended December 31, 2001).                                   |
| 4.13       |  | SubscriptionAgreement, dated as of March 12, 2002, executed by Berkshire HathawayInc. (incorporated by reference to Exhibit 4.13 to MEHC's AnnualReport on Form 10-K for the year ended December 31, 2001).                                  |
| 4.14       |  | Amended and Restated Declaration of Trust ofMidAmerican Capital Trust III, dated as of August 16, 2002(incorporated by reference to Exhibit 4.14 of MEHC's RegistrationStatement No. 333-101699 dated December 6, 2002).                     |
| 4.15       |  | Amended and Restated Declaration of Trust ofMidAmerican Capital Trust II, dated as of March 12, 2002 (incorporatedby reference to Exhibit 4.15 of MEHC's Registration Statement No.333-101699 dated December 6, 2002).                       |
| 4.16       |  | Amended and Restated Declaration of Trust ofMidAmerican Capital Trust I, dated as of March 14, 2000 (incorporatedby reference to Exhibit 4.16 of MEHC's Registration Statement No.333-101699 dated December 6, 2002).                        |
| 4.17       |  | Indenture, dated as of August 16, 2002, betweenMEHC and the Bank of New York, as Trustee (incorporated by reference toExhibit 4.17 of MEHC's Registration Statement No. 333-101699dated December 6, 2002).                                   |
| 4.18       |  | SubscriptionAgreement, dated as of August 16, 2002, executed by Berkshire HathawayInc. (incorporated by reference to Exhibit 4.18 of MEHC'sRegistration Statement No. 333-101699 dated December 6,2002).                                     |
| 4.19       |  | Shareholders Agreement, datedas of March 14, 2000 (incorporated by reference to Exhibit 4.19 ofMEHC's Registration Statement No. 333-101699 dated December 6,2002).                                                                          |
| 10.1       |  | Employment Agreement betweenMEHC and David L. Sokol, dated May 10, 1999 (incorporated by referenceto Exhibit 10.1 to MEHC's Annual Report on Form 10-K/A for theyear ended December 31, 1999).                                               |
| 10.2       |  | Amendment No. 1 to the Amended and RestatedEmployment Agreement between MEHC and David L. Sokol, dated March 14,2000 (incorporated by reference to Exhibit 10.2 to MEHC's AnnualReport on Form 10-K/A for the year ended December 31, 1999). |
| 10.3       |  | Non-Qualified Stock Options Agreements of DavidL. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit10.3 of MEHC's Registration Statement No. 333-101699 datedDecember 6, 2002).                                              |
| 10.4       |  | Amended andRestated Employment Agreement between MEHC and Gregory E. Abel, datedMay 10, 1999 (incorporated by reference to Exhibit 10.3 to MEHC'sAnnual Report on Form 10-K/A for the year ended December 31,1999).                          |
| 10.5       |  | Non-Qualified Stock OptionsAgreements of Gregory E. Abel, dated March 14, 2000 (incorporated byreference 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 Exhibit10.5 to MEHC's Annual Report on Form 10-K/A for the year endedDecember 31, 1999).                                         |
|            |

118

----

|            |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |  |  |  |  |
|------------|--|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--|--|--|--|
| ExhibitNo. |  |
| 10.7       |  | MidAmerican EnergyHoldings Company, Amended and Restated Long Term Incentive PartnershipPlan dated as of January 1, 2003 (incorporated by reference to Exhibit10.1 of MEHC's Quarterly Report on Form 10-Q for the quarterended March 31, 2003).                                                                                                                                                                                                                                                                                                          |
| 10.8       |  | 125 MW PowerPlant-Upper Mahiao Agreement, dated September 6, 1993, betweenPNOC-Energy Development Corporation and Ormat, Inc. as amended by theFirst Amendment to 125 MW Power Plant Upper Mahiao Agreement, dated asof January 28, 1994, the Letter Agreement dated February 10, 1994, theLetter Agreement dated February 18, 1994 and the Fourth Amendment to125 MW Power Plant-Upper Mahiao Agreement, dated as of March 7, 1994(incorporated by reference to Exhibit 10.95 to MEHC's AnnualReport on Form 10-K for the year ended December 31, 1993). |
| 10.9       |  | Credit Agreement, dated April 8, 1994, among CECebu Geothermal Power Company, Inc., the Banks thereto, Credit Suisseas Agent (incorporated by reference to Exhibit 10.96 to MEHC'sAnnual Report on Form 10-K for the year ended December 31,1993).                                                                                                                                                                                                                                                                                                        |
| 10.10      |  | Credit Agreement, dated as ofApril 8, 1994, between CE Cebu Geothermal Power Company, Inc.,Export-Import Bank of the United States (incorporated by reference toExhibit 10.97 to MEHC'sAnnual Report on Form 10-K for the yearended December 31, 1993).                                                                                                                                                                                                                                                                                                   |
| 10.11      |  | PledgeAgreement, dated as of April 8, 1994, among CE Philippines Ltd,Ormat-Cebu Ltd., Credit Suisse as Collateral Agent and CE CebuGeothermal Power Company, Inc. (incorporated by reference to Exhibit10.98 to MEHC's Annual Report on Form 10-K for the year endedDecember 31, 1993).                                                                                                                                                                                                                                                                   |
| 10.12      |  | Overseas PrivateInvestment Corporation Contract of Insurance, dated April 8, 1994,between the Overseas Private Investment Corporation and the Companythrough its subsidiaries CE International Ltd., CE Philippines Ltd.,and Ormat-Cebu Ltd. (incorporated by reference to Exhibit 10.99 toMEHC's Annual Report on Form 10-K for the year ended December 31,1993).                                                                                                                                                                                        |
| 10.13      |  | 180 MW PowerPlant-Mahanagdong Agreement, dated September 18, 1993, betweenPNOC-Energy Development Corporation and CE Philippines Ltd. and theCompany, as amended by the First Amendment to Mahanagdong Agreement,dated June 22, 1994, the Letter Agreement dated July 12, 1994, theLetter Agreement dated July 29, 1994, and the Fourth Amendment toMahanagdong Agreement, dated March 3, 1995 (incorporated by referenceto Exhibit 10.1 00 to MEHC's Annual Report on Form 10-K for theyear ended December 31, 1993).                                    |
| 10.14      |  | CreditAgreement, dated as of June 30, 1994, among CE Luzon Geothermal PowerCompany, Inc., American Pacific Finance Company, the Lenders partythereto, and Bank of America National Trust and Savings Association asAdministrative Agent (incorporated by reference to Exhibit 10.101 toMEHC's Annual Report on Form 10-K for the year ended December 31,1993).                                                                                                                                                                                            |
| 10.15      |  | Credit Agreement, dated as ofJune 30, 1994, between CE Luzon Geothermal Power Company, Inc. andExport-Import Bank of the United States (incorporated by reference toExhibit 10.102 to MEHC's Annual Report on Form 10-K for the yearended December 31, 1993).                                                                                                                                                                                                                                                                                             |
| 10.16      |  | FinanceAgreement, dated as of June 30, 1994, between CE Luzon Geothermal PowerCompany, Inc. and Overseas Private Investment Corporation (incorporatedby reference to Exhibit 10.103 to MEHC's Annual Report on Form10-K for the year ended December 31, 1993).                                                                                                                                                                                                                                                                                            |
|            |

119

----

|            |  |                                                                                                                                                                                                                                                                                                                                                                                                                        |  |  |  |  |
|------------|--|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--|--|--|--|
| ExhibitNo. |  |
| 10.17      |  | Pledge Agreement,dated as of June 30, 1994, among CE Mahanagdong Ltd., Kiewit EnergyInternational (Bermuda) Ltd., Bank of America National Trust andSavings Association as Collateral Agent and CE Luzon Geothermal PowerCompany, Inc. (incorporated by reference to Exhibit 10.104 toMEHC's Annual Report on Form 10-K for the year ended December 31,1993).                                                          |
| 10.18      |  | Overseas Private InvestmentCorporation Contract of Insurance, dated July 29, 1994, betweenOverseas Private Investment Corporation and the Company, CEInternational Ltd., CE Mahanagdong Ltd. and American Pacific FinanceCompany and Amendment No. 1, dated August 3, 1994 (incorporated byreference to Exhibit 10.105 to MEHC's Annual Report on Form 10-Kfor the year ended December 31, 1993).                      |
| 10.19      |  | 231 MW Power Plant-Malitbog Agreement, datedSeptember 10, 1993, between PNOC-Energy Development Corporation andMagma Power Company and the First and Second Amendments thereto, datedDecember 8, 1993 and March 10, 1994, respectively (incorporated byreference to Exhibit 10.106 to MEHC's Annual Report on Form 10-Kfor 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 andCredit Suisse, as Bank Agent (incorporated by reference to Exhibit10.107 to MEHC's Annual Report on Form 10-K for the year endedDecember 31, 1993).                                                                                                                                              |
| 10.21      |  | FinanceAgreement, dated as of November 10, 1994, between Visayas GeothermalPower Company and Overseas Private Investment Corporation (incorporatedby reference to Exhibit 10.108 to MEHC's Annual Report on Form10-K for the year ended December 31, 1993).                                                                                                                                                            |
| 10.22      |  | Pledge and Security Agreement, dated as ofNovember 10, 1994, among Broad Street Contract Services, Inc., MagmaPower Company, Magma Netherlands B.V. and Credit Suisse, as Bank Agent(incorporated by reference to Exhibit 10.109 to MEHC's AnnualReport on Form 10-K for the year ended December 31, 1993).                                                                                                            |
| 10.23      |  | Overseas Private Investment Corporation Contractof Insurance, dated December 21, 1994,between Overseas PrivateInvestment Corporation and Magma Netherlands, B.V. (incorporated byreference to Exhibit 10.110 to MEHC's Annual Report on Form10-Kfor the year ended December 31, 1993).                                                                                                                                 |
| 10.24      |  | Agreement as to Certain Common Representations,Warranties, Covenants and Other Terms, dated November 10, 1994, betweenVisayas Geothermal Power Company, Visayas Power Capital Corporation,Credit Suisse, as Bank Agent, Overseas Private Investment Corporationand the Banks named therein (incorporated by reference to Exhibit10.111 to MEHC's 1994 Annual Report on Form 10-K for the yearended December 31, 1993). |
| 10.25      |  | TrustIndenture, dated as of November 27, 1995, between the CE Casecnan Waterand Energy Company, Inc. and Chemical Trust Company of California(incorporated by reference to Exhibit 4.1 to CE Casecnan Water andEnergy Company, Inc.'s Registration Statement on Form S-4 datedJanuary 25, 1996).                                                                                                                       |
| 10.26      |  | Amended andRestated Casecnan Project Agreement, dated June 26, 1995, between theNational Irrigation Administration and CE Casecnan Water and EnergyCompany Inc. (incorporated by reference to Exhibit 10.1 to CE CasecnanWater and Energy Company, Inc.'s Registration Statement on FormS-4 dated January 25, 1996).                                                                                                   |
|            |

120

----

|            |  |                                                                                                                                                                                                                                                                                                                                           |  |  |  |  |
|------------|--|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--|--|--|--|
| ExhibitNo. |  |
| 10.27      |  | Term Loan andRevolving Facility Agreement, dated as of October 28, 1996, among CEElectric UK Holdings, CE Electric UK plc and Credit Suisse(incorporated by reference to Exhibit 10.130 to MEHC's AnnualReport on Form 10-K for the year ended December 31, 1995).                                                                        |
| 10.28      |  | Indenture and First Supplemental Indenture,dated March 11, 1999, between MidAmerican Funding LLC and IBJ WhitehallBank & Trust Company and the First Supplement thereto relating tothe $700 million Senior Notes and Bonds (incorporated by reference toMEHC's Annual Report on Form 10-K for the year ended December 31,1998).       |
| 10.29      |  | General Mortgage Indenture andDeed of Trust, dated as of January 1, 1993, between Midwest PowerSystems Inc. and Morgan Guaranty Trust Company of New York, Trustee(incorporated by reference to Exhibit 4(b)-1 to the Midwest ResourcesInc. Annual Report on Form 10-K for the year ended December 31, 1992,Commission File No. 1-10654). |
| 10.30      |  | FirstSupplemental Indenture, dated as of January 1, 1993, between MidwestPower Systems Inc. and Morgan Guaranty Trust Company of New York,Trustee (incorporated by reference to Exhibit 4(b)-2 to the MidwestResources Inc. Annual Report on Form 10-K for the year ended December31, 1992, Commission File No. 1-10654).                 |
| 10.31      |  | Second Supplemental Indenture, dated as ofJanuary 15, 1993, between Midwest Power Systems Inc. and MorganGuaranty Trust Company of New York, Trustee (incorporated by referenceto Exhibit 4(b)-3 to the Midwest Resources Inc. Annual Report on Form10-K for the year ended December 31, 1992, Commission File No.1-10654).               |
| 10.32      |  | Third SupplementalIndenture, dated as of May 1, 1993, between Midwest Power Systems Inc.and Morgan Guaranty Trust Company of New York, Trustee (incorporated byreference to Exhibit 4.4 to the Midwest Resources Inc. Annual Report onForm 10-K for the year ended December 31, 1993, Commission File No.1-10654).                        |
| 10.33      |  | Fourth SupplementalIndenture, dated as of October 1, 1994, between Midwest Power SystemsInc. and Harris Trust and Savings Bank, Trustee (incorporated byreference to Exhibit 4.5 to the Midwest Resources Inc. Annual Report onForm 10-K for the year ended December 31, 1994, Commission File No.1-10654).                               |
| 10.34      |  | Fifth SupplementalIndenture, dated as of November 1, 1994, between Midwest Power SystemsInc. and Harris Trust and Savings Bank, Trustee (incorporated byreference to Exhibit 4.6 to the Midwest Resources Inc. Annual Report onForm 10-K for the year ended December 31, 1994, Commission File No.1-10654).                               |
| 10.35      |  | Sixth SupplementalIndenture, dated as of July 1, 1995, between Midwest Power Systems Inc.and Harris Trust and Savings Bank, Trustee (incorporated by referenceto Exhibit 4.15 to the MidAmerican Energy Company Annual Report on Form10-K for the year ended December 31, 1995, Commission File No.1-11505).                              |
| 10.36      |  | Indenture of Mortgage andDeed of Trust, dated as of March 1, 1947 (incorporated by reference toExhibit 7B filed by Iowa-Illinois Gas and Electric Company as part ofCommission File No. 2-6922).                                                                                                                                          |
| 10.37      |  | SixthSupplemental Indenture, dated as of July 1, 1967 (incorporated byreference to Exhibit 2.08 filed by Iowa-Illinois Gas and ElectricCompany as part of Commission File No. 2-28806).                                                                                                                                                   |
| 10.38      |  | Twentieth Supplemental Indenture, dated as ofMay 1, 1982 (incorporated by reference to Exhibit 4.B.23 to theIowa-Illinois Gas and Electric Company Quarterly Report on Form 10-Qfor the period ended June 30, 1982, Commission File No.1-3573).                                                                                           |
|            |

121

----

|            |  |                                                                                                                                                                                                                                                                                                                                                                              |  |  |  |  |
|------------|--|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--|--|--|--|
| ExhibitNo. |  |
| 10.39      |  | Resignation andAppointment of successor Individual Trustee (incorporated by referenceto Exhibit 4.B.30 filed by Iowa-Illinois Gas and Electric Company aspart of Commission File No. 33-39211).                                                                                                                                                                              |
| 10.40      |  | Twenty-Eighth Supplemental Indenture, dated asof May 15, 1992 (incorporated by reference to Exhibit 4.31.B to theIowa-Illinois Gas and Electric Company Current Report on Form 8-K datedMay 21, 1992, Commission File No. 1-3573).                                                                                                                                           |
| 10.41      |  | Supplemental Agreement between CE Casecnan Waterand Energy Company, Inc. and the Philippines National IrrigationAdministration dated as of September 29, 2003 (incorporated byreference to Exhibit 10.41 of MEHC's annual report on Form 10-Kfor the year ended December 31, 2003).                                                                                          |
| 10.42      |  | Thirtieth Supplemental Indenture, dated as ofOctober 1, 1993 (incorporated by reference to Exhibit 4.34.A to theIowa-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 ofJuly 1, 1995, between Iowa-Illinois Gas and Electric Company and HarrisTrust and Savings Bank, Trustee (incorporated by reference to Exhibit4.16 to the MidAmerican Energy Company Annual Report on Form 10-K forthe year ended dated December 31, 1995, Commission File No.1-11505).                                        |
| 10.44      |  | Sixth Amendment to 180 MWPower Plant-Mahanagdong Agreement, dated August  31, 2003,between PNOC-Energy Development Corporation and CE Luzon GeothermalPower Company, Inc. (incorporated by reference to Exhibit 10.44 ofMEHC's annual report on Form 10-K for the year ended December 31,2003).                                                                              |
| 10.45      |  | Third Amendment to 231 MWPower Plant-Malitbog Agreement, dated August  31, 2003, betweenPNOC-Energy Development Corporation and Visayas Geothermal PowerCompany, Inc. (incorporated by reference to Exhibit 10.45 ofMEHC's annual report on Form 10-K for the year ended December 31,2003).                                                                                  |
| 10.46      |  | Seventh Amendment to 125 MWPower Plant-Upper Mahiao Agreement, dated August  31, 2003,between PNOC-Energy Development Corporation and CE Cebu GeothermalPower Company, Inc. (incorporated by reference to Exhibit 10.46 ofMEHC's annual report on Form 10-K for the year ended December 31,2003).                                                                            |
| 10.47      |  | Fiscal Agency Agreement, datedas of October 15, 2002, between Northern Natural Gas Company and J.P.Morgan Trust Company, National Association, Fiscal Agent, relating tothe $300,000,000 in principal amount of the 5.375% Senior Notesdue 2012 (incorporated by reference to Exhibit 10.47 of MEHC'sannual report on Form 10-K for the year ended December 31,2003).        |
| 10.48      |  | Trust Indenture, dated as ofAugust 13, 2001, among Kern River Funding Corporation, Kern River GasTransmission Company and the JP Morgan Chase Bank, as Trustee, relatingto the $510,000,000 in principal amount of the 6.676% SeniorNotes due 2016 (incorporated by reference to Exhibit 10.48 ofMEHC'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, KernRiver 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 ofMEHC's annual report on Form 10-K for the year ended December 31,2003). |
|            |

122

----

|            |  |                                                                                                                                                                                                                                                                                                              |  |  |  |  |
|------------|--|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--|--|--|--|
| ExhibitNo. |  |
| 10.50      |  | CalEnergy Company,Inc. Voluntary Deferred Compensation Plan, effective December 1, 1997,First Amendment, dated as of August 17, 1999, and Second Amendmenteffective March 2000 (incorporated by reference to Exhibit 10.50 ofMEHC's Registration Statement No. 333-101699 dated December 6,2002).            |
| 10.51      |  | MidAmerican Energy HoldingsCompany Executive Voluntary Deferred Compensation Plan (incorporated byreference to Exhibit 10.51 of MEHC's Registration Statement No.333-101699 dated December 6, 2002).                                                                                                         |
| 10.52      |  | MidAmerican Energy Company First Amended andRestated Supplemental Retirement Plan for Designated Officers dated asof May 10, 1999 (incorporated by reference to Exhibit 10.52 ofMEHC's Registration Statement No. 333-101699 dated December 6,2002).                                                         |
| 10.53      |  | MidAmerican Energy CompanyRestated Executive Deferred Compensation Plan (incorporated byreference to Exhibit 10.6 to MEHC's Annual Report on Form 10-K/Afor the year ended December 31, 1999).                                                                                                               |
| 10.54      |  | MidAmerican Energy Holdings Company RestatedDeferred Compensation Plan-Board of Directors (incorporated byreference to Exhibit 10 to MEHC's Quarterly Report on Form 10-Qfor the quarter ended June 30, 1999).                                                                                               |
| 10.55      |  | MidAmerican Energy Company Combined MidwestResources/Iowa Resources Restated Deferred Compensation Plan-Board ofDirectors (incorporated by reference to Exhibit 10.63 to MEHC'sAnnual 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 CompanySupplemental Retirement Plan (incorporated by reference to Exhibit10.10 to the Midwest Resources Inc. Annual Report on Form 10-K for theyear 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 Exhibit10.24 to the Midwest Resources Inc. Annual Report on Form 10-K for theyear ended December 31, 1994, Commission File No. 1-10654).                                                             |
| 10.58      |  | Iowa-Illinois Gas and Electric CompanySupplemental Retirement Plan for Designated Officers, as amended as ofJuly 28, 1994 (incorporated by reference to the Iowa-Illinois Gas andElectric Company Annual Report on Form 10-K for the year ended December31, 1994, Commission File No. 1-3573).               |
| 10.59      |  | Iowa-Illinois Gas and Electric CompanyCompensation Deferral Plan for Designated Officers, as amended as ofJuly 1, 1993 (incorporated by reference to Exhibit 10.K.2 to theIowa-Illinois Gas and Electric Company Annual Report on Form 10-K forthe year ended December 31, 1993, Commission File No.1-3573). |
| 10.60      |  | Iowa-Illinois Gas andElectric Company Compensation Deferral Plan for Key Employees, dated asof April 26, 1991 (incorporated by reference to the Iowa-Illinois Gasand Electric Company Annual Report on Form 10-K for the year endedDecember 31, 1991, Commission File No. 1-3573).                           |
| 10.61      |  | Iowa-Illinois Gas and Electric Company Board ofDirectors' Compensation Deferral Plan (incorporated by referenceto Exhibit 10.K.4 to the Iowa-Illinois Gas and Electric Company AnnualReport on Form 10-K for the year ended December 31, 1992, CommissionFile No. 1-3573).                                   |
|            |

123

----

|            |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |  |  |  |  |
|------------|--|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--|--|--|--|
| ExhibitNo. |  |
| 10.62      |  | Iowa Utilities BoardSettlement Agreement among MidAmerican Energy Company, Office ofConsumer Advocate, Iowa Energy Consumers, Aluminum Company of America,Deere & Company, Cargill Inc., U.S. Gypsum Company, InterstatePower Company and IES Utilities, Inc. (incorporated by reference toExhibit 10.16 to the MidAmerican Funding, LLC and MidAmerican EnergyCompany respective Annual Reports on the combined Form 10-K for theyear ended December 31, 2000, Commission File Nos. 333-90553 and1-11505, respectively). |
| 10.63      |  | Share SaleAgreement, 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'sRegistration Statement No. 333-101699 dated December 6,2002).                                                                                                                                                                                                                                                           |
| 10.64      |  | Purchase Agreement, dated asof March 7, 2002, among The Williams Companies, Inc., Williams GasPipeline Company, LLC, Williams Western Pipeline Company LLC, KernRiver Acquisition, LLC and MEHC, KR Holding, LLC, KR Acquisition 1, LLCand KR Acquisition 2, LLC (incorporated by reference to Exhibit 99.2 toMEHC's Current Report on Form 8-K dated March 28,2002).                                                                                                                                                         |
| 10.65      |  | MidAmerican Energy HoldingsCompany Executive Incremental Profit Sharing Plan (incorporated byreference to Exhibit 10.2 of MEHC's Quarterly Report on Form 10-Qfor the quarter ended March 31, 2003.)                                                                                                                                                                                                                                                                                                                          |
| 10.67      |  | Purchase and Sale Agreement, dated as of July28, 2002, between Dynegy Inc., NNGC Holding Company, Inc. and MEHC(incorporated by reference to Exhibit 99.2 to MEHC's CurrentReport on Form 8-K dated July 30,2002).                                                                                                                                                                                                                                                                                                            |
| 14.1       |  | MidAmerican Energy HoldingsCompany Code of Ethics for Chief Executive Officer, Chief FinancialOfficer and Other Covered Officers (incorporated by reference toExhibit 14.1 of MEHC's annual report on Form 10-K for the yearended December 31, 2003).                                                                                                                                                                                                                                                                         |
| 21.1       |  | Subsidiariesof the Registrant (incorporated by reference to Exhibit 21.1 ofMEHC's annual report on Form 10-K for the year ended December 31,2003).                                                                                                                                                                                                                                                                                                                                                                            |
| 24.1       |  | Power of Attorney (incorporatedby reference to Exhibit 24.1 of MEHC's annual report on Form 10-Kfor the year ended December 31, 2003).                                                                                                                                                                                                                                                                                                                                                                                        |
| 31.1       |  | Chief Executive Officer's CertificatePursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                               |
| 31.2       |  | Chief Financial Officer's CertificatePursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                               |
| 32.1       |  | Chief Executive Officer's CertificatePursuant to Section 906 of the Sarbanes-Oxley Act of2002.                                                                                                                                                                                                                                                                                                                                                                                                                                |
| 32.2       |  | Chief Financial Officer'sCertificate Pursuant to Section 906 of the Sarbanes-Oxley Act of2002.                                                                                                                                                                                                                                                                                                                                                                                                                                |
|            |

124

----