AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON DECEMBER 6, 2002
REGISTRATION NO. 333-
================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

------------------------
FORM S-4
REGISTRATION STATEMENT UNDER
THE SECURITIES ACT OF 1933
------------------------

MIDAMERICAN ENERGY HOLDINGS COMPANY
(Exact name of registrant as specified in its charter)

IOWA 4900 94-2213782

(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification No.)

666 GRAND AVENUE
DES MOINES, IOWA 50309
(515) 242-4300
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)

DOUGLAS L. ANDERSON
GENERAL COUNSEL
MIDAMERICAN ENERGY HOLDINGS COMPANY
302 SOUTH 36TH STREET
SUITE 400
OMAHA, NE 68131
(402) 341-4500
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
------------------------
Copy to:
PETER J. HANLON, ESQ.
WILLKIE FARR & GALLAGHER
787 SEVENTH AVENUE
NEW YORK, NY 10019
(212) 728-8000

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon
as practicable after the effective date of this Registration Statement.

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

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

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

------------------------
CALCULATION OF REGISTRATION FEE

=========================================================================================================================
PROPOSED MAXIMUM PROPOSED MAXIMUM
TITLE OF EACH CLASS OF AMOUNT TO BE OFFERING PRICE AGGREGATE AMOUNT OF
SECURITIES TO BE REGISTERED REGISTERED PER NOTE(1) OFFERING PRICE(1) REGISTRATION FEE
- -------------------------------------------------------------------------------------------------------------------------

4.625% Senior Notes due 2007 ......... $200,000,000 100% $200,000,000 $18,400
- -------------------------------------------------------------------------------------------------------------------------
5.875% Senior Notes due 2012 ......... $500,000,000 100% $500,000,000 $46,000
- -------------------------------------------------------------------------------------------------------------------------
Total ................................ $700,000,000 100% $700,000,000 $64,400
=========================================================================================================================

(1) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457 under the Securities Act of 1933, as amended.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THE REGISTRATION STATEMENT
SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION,
ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.

================================================================================

THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY
NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN
OFFER TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY THESE
SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.

SUBJECT TO COMPLETION, DATED , 200

PROSPECTUS
[MIDAMERICAN ENERGY HOLDINGS COMPANY LOGO]

---------------------

OFFER TO EXCHANGE

---------------------

UP TO $200,000,000 4.625% SENIOR NOTES DUE 2007 FOR
ALL OUTSTANDING 4.625% SENIOR NOTES DUE 2007
AND
UP TO $500,000,000 5.875% SENIOR NOTES DUE 2012 FOR
ALL OUTSTANDING 5.875% SENIOR NOTES DUE 2012

---------------------

o We are offering to exchange new registered 4.625% senior notes due 2007 for
all of our outstanding unregistered 4.625% senior notes due 2007 and new
registered 5.875% senior notes for all of our outstanding 5.875% senior
notes.

o The exchange offer expires at 5:00 p.m., New York City time, on ,
200 , unless extended.

o The exchange offer is subject to customary conditions that may be waived by
us.

o All original notes outstanding that are validly tendered and not validly
withdrawn prior to the expiration of the exchange offer will be exchanged
for the exchange notes.

o Tenders of original notes may be withdrawn at any time before 5:00 p.m.,
New York City time, on the expiration date of the exchange offer.

o The exchange of notes will not be a taxable exchange for U.S. federal
income tax purposes.

o We will not receive any proceeds from the exchange offer.

o The terms of the exchange notes to be issued are substantially identical to
the terms of the original notes, except that the exchange notes will not
have transfer restrictions, and you will not have registration rights.

o There is no established trading market for the exchange notes, and we do
not intend to apply for listing of the exchange notes on any securities
exchange or market quotation system.

SEE "RISK FACTORS" BEGINNING ON PAGE 14 FOR A DISCUSSION OF MATTERS YOU
SHOULD CONSIDER BEFORE YOU PARTICIPATE IN THE EXCHANGE OFFER.

---------------------

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

---------------------

The date of this Prospectus is , 200

TABLE OF CONTENTS

PAGE
-----

SUMMARY ................................. 1
RISK FACTORS ............................ 14
FORWARD-LOOKING STATEMENTS .............. 24
USE OF PROCEEDS ......................... 25
THE EXCHANGE OFFER ...................... 26
CAPITALIZATION .......................... 34
SELECTED CONSOLIDATED FINANCIAL AND
OPERATING DATA ....................... 35
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS ........................... 38
QUANTITATIVE AND QUALITATIVE
DISCLOSURE ABOUT MARKET RISK ......... 55
BUSINESS ................................ 56

PAGE
-----

REGULATION .............................. 77
LEGAL PROCEEDINGS ....................... 90
MANAGEMENT .............................. 93
DESCRIPTION OF THE NOTES ................ 102
CERTAIN UNITED STATES FEDERAL INCOME
TAX CONSIDERATIONS ................... 117
PLAN OF DISTRIBUTION .................... 121
NOTICE TO CANADIAN RESIDENTS ............ 122
LEGAL MATTERS ........................... 122
EXPERTS ................................. 122
WHERE YOU CAN FIND MORE INFORMATION...... 122
FINANCIAL STATEMENTS .................... F-1

------------

In this prospectus, references to "U.S. dollars," "dollars," "US $," "$" or
"cents" are to the currency of the United States and references to " (pounds
sterling)," "sterling," "pence" or "p" are to the currency of the United
Kingdom. In this prospectus, MW means megawatts, MWh means megawatt hours, Bcf
means billion cubic feet, mmcf means million cubic feet, MMBtus means million
British thermal units, GWh means gigawatts per hour, kV means 1000 volts, and
Tcf means trillion cubic feet.

------------

This prospectus incorporates important business and financial information
about us that is not included or delivered with this prospectus. We will provide
this information to you at no charge upon written or oral request directed to
Douglas L. Anderson, General Counsel MidAmerican Energy Holdings Company, 302
South 36th Street, Suite 400, Omaha, Nebraska 68131, (402) 341-4500. In order to
ensure timely delivery of the information, any request should be made by
, 2002.

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

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

NOTICE TO NEW HAMPSHIRE RESIDENTS

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

iii

SUMMARY

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

MIDAMERICAN ENERGY HOLDINGS COMPANY

OVERVIEW

We are a United States-based global energy company. Our principal
businesses are regulated electric and natural gas utilities, regulated
interstate natural gas transmission and electric power generation. Our
operations are organized and managed on seven distinct platforms which we refer
to as: MidAmerican Energy, Northern Natural Gas, Kern River, CE Electric UK
(which includes Northern Electric and Yorkshire Electricity), CalEnergy
Generation-Domestic, CalEnergy Generation-Foreign and HomeServices. Through six
of these platforms, we own and operate a combined electric and natural gas
utility company in the United States, two natural gas pipeline companies in the
United States, two electricity distribution companies in the United Kingdom and
a diversified portfolio of domestic and international electric power projects.
We also own the second largest residential real estate brokerage firm in the
United States. The following is a chart of our operating platforms and the
principal lines of business in which they are engaged:

----------------------
MidAmerican Energy
Holdings Company
----------------------
|
|
-------------------------------------------------------------------------------------------------
| | | | | | |
| | | | | | |
- ------------ ----------- ------------- ---------------------- ------------ ------------ -------------

MidAmerican Northern Kern River CE Electric UK CalEnergy CalEnergy HomeServices
Energy Natural Gas ---------------------- Generation- Generation-
Northern | Yorkshire Domestic Foreign
Electric | Electricity
- ------------ ----------- ------------- ----------------------- ------------ ------------ -------------
Regulated Regulated Regulated Regulated electricity Non-utility Non-utility Real estate
gas and natural gas natural gas distribution power power brokerage and
electric transmission transmission generation generation related
utility services

Our principal subsidiaries generate, transmit, store, distribute and supply
energy. Our electric and natural gas utility subsidiaries currently serve
approximately 4.3 million electricity customers and approximately 653,000
natural gas customers. Our natural gas pipeline subsidiaries operate interstate
natural gas transmission systems with approximately 17,500 miles of pipeline in
operation and peak delivery capacity of 5.3 Bcf of natural gas per day. We have
interests in 6,185 net owned megawatts of power generation facilities in
operation and construction, including 4,618 net owned megawatts in facilities
that are part of the regulated return asset base of our electric utility
business (as further described in "Business--MidAmerican Energy--Electric
Operations") and 1,567 net owned megawatts in non-utility power generation
facilities. Substantially all of the non-utility power generation facilities
have long-term contracts for the sale of energy and/or capacity from the
facilities.

We have recently achieved significant growth in our asset base, while
expanding and diversifying our underlying revenue and earnings base. In the past
four years, we have consummated the four significant acquisitions described
below.

In March 1999, our predecessor, CalEnergy Company, Inc., acquired a
publicly traded company which owned the largest combined electric and gas
utility in Iowa. The primary asset of this company consisted of the MidAmerican
Energy platform.

In September 2001, we acquired the electricity distribution business of
Yorkshire Power Group Ltd., or Yorkshire Electricity, which was one of the
twelve original regional electric companies in the United Kingdom, and
simultaneously sold the electricity and gas supply business of Northern Electric
plc, or Northern Electric, to the former owner of Yorkshire Electricity.

In March 2002, we acquired Kern River Gas Transmission Company, or Kern
River, which owns a 926-mile interstate natural gas pipeline extending from
Wyoming to markets in California, Nevada and Utah and accesses natural gas
supplies from large producing regions in the Rocky Mountains and Canada.

In August 2002, we acquired Northern Natural Gas Company, or Northern
Natural Gas, for $928 million in cash (subject to adjustment for working
capital). We used the proceeds from a $950 million investment in our subsidiary
trust's preferred securities by Berkshire Hathaway Inc., or Berkshire Hathaway,
to finance this acquisition.

Northern Natural Gas owns a 16,600-mile interstate natural gas pipeline
extending from southwest Texas to the upper Midwest region of the United States
with a design capacity of 4.4 Bcf of natural gas per day. Northern Natural Gas
also operates three natural gas storage facilities and two liquefied natural gas
peaking units with a total storage capacity of 59 Bcf and peak delivery
capability of over 1.3 Bcf of natural gas per day. Northern Natural Gas accesses
natural gas supply from many of the larger producing regions in North America,
including the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian
basins. The pipeline system provides transportation and storage services to
utilities, municipalities, other pipeline companies, gas marketers and
industrial and commercial users.

Our revenues for the year ended December 31, 2001 were $5.3 billion and our
total assets were $12.6 billion as of December 31, 2001. Our revenues for the
nine months ended September 30, 2002 (which includes Kern River for the period
from March 27, 2002 and Northern Natural Gas for the period from August 16,
2002) were $3.5 billion and our total assets were $17.0 billion as of September
30, 2002. As of September 30, 2002, the total consolidated assets of our four
utility platforms, MidAmerican Energy, Northern Natural Gas, Kern River and CE
Electric UK, aggregated approximately 82% of our total assets.

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

STRATEGY

Our business strategy is focused upon the successful operation, management
and growth of our diversified portfolio of energy assets and on the pursuit of
strategic utility acquisitions and selected other investment opportunities,
principally in the United States. As a privately owned company, we are able to
focus on long-term risk-adjusted cash flow returns from our businesses. We seek
to manage and operate our energy assets such that their cost structure makes us
a low-cost provider of energy and energy services.

In order to implement this strategy, we plan to:

our investments. In addition, we have worked closely and successfully with
customers and with regulatory and legislative authorities to ensure that our
business initiatives are consistent with our obligations to serve customers and
with the requirements of the regulatory regimes under which we operate. We have
identified and are proceeding with a number of significant capital investment
opportunities that we believe offer attractive risk-adjusted returns. These
opportunities include a $1.2 billion program to expand MidAmerican Energy's base
of electric generation facilities in Iowa and a $1.2 billion expansion to
approximately double the design delivery capacity of our Kern River pipeline by
2003, which we refer to as the 2003 Expansion Project.

GROW AND DIVERSIFY THROUGH ACQUISITIONS OF HIGH QUALITY REGULATED UTILITY
BUSINESSES. We believe that well managed regulated utility businesses can
provide a stable cash flow profile and a reasonable risk-adjusted equity return
to their owners. Our acquisitions of Northern Electric in 1997 and MidAmerican
Energy in 1999 provided us with specialized skills and expertise, particularly
in operations and regulatory affairs, which have enhanced our competitive
position and positioned us favorably for future growth in our targeted sectors.
In the past fifteen months, we completed three acquisitions of utility operating
companies, Yorkshire Electricity, Kern River and Northern Natural Gas, each of
which has added substantially to our base of utility operating assets and cash
flows. We believe that these acquisitions helped us achieve additional
diversification of our utility business with respect to sources of cash flow,
types of utility operations, geography and regulatory regimes.

CAPITALIZE ON CHANGE IN OUR INDUSTRY AND ON OUR SUPERIOR ACCESS TO CAPITAL
IN ORDER TO MAKE ATTRACTIVE INVESTMENTS. The global energy markets, particularly
those in the United States, are experiencing a period of significant change due
to various factors, including the macroeconomic environment, fluctuating
commodity prices, regulatory and legislative developments and financial
restructurings by many market participants. We and our shareholders believe that
such an environment provides opportunities for disciplined companies with access
to investment capital to achieve reasonable risk-adjusted returns by acquiring
high quality companies and assets at reasonable prices. Warren Buffett, Chairman
of the Board and Chief Executive Officer of Berkshire Hathaway, has publicly
stated that we are a core holding of Berkshire Hathaway and are expected to be
its principal vehicle for investments in the energy sector. In 2002 to date, we
completed two acquisitions of interstate natural gas transmission pipelines,
which we funded with a majority of the proceeds of Berkshire Hathaway's
investment in $1.273 billion of our trust preferred securities and $402 million
of our zero coupon convertible preferred stock, all of which is subordinated to
our senior indebtedness. We believe that our ability to successfully negotiate
and complete these acquisitions was facilitated by our access to capital from
Berkshire Hathaway and that there will continue to be opportunities in the
current environment to make additional acquisitions that further enhance our
business mix, risk profile, capitalization and investment returns.

ENHANCE OUR INVESTMENT GRADE CREDIT PROFILE AND THAT OF OUR SUBSIDIARIES.
Our financing strategy is focused on capitalizing and managing our utility
subsidiaries in a manner consistent with maintenance of strong credit ratings,
thereby supporting our credit profile with more predictable underlying cash
flows from these subsidiaries. This strategy is driven by our belief that strong
credit ratings allow us to minimize our financing costs over the long term and
to optimize our investment returns, while also retaining the financial
flexibility to pursue attractive capital investment opportunities as and when
they are available. Our strategy is to finance our operating subsidiaries with
debt that in almost all cases is non-recourse to us, which has allowed us to
reduce financing costs by taking advantage of the stable, investment grade
characteristics of our subsidiaries' utility assets.

base are not a material part of our business and are conducted pursuant to
closely monitored risk management policies and practices that are intended to
minimize our exposure to fluctuations in energy commodity prices and to
counterparty credit risk. A core tenet of our acquisition and investment
philosophy is that we will only pursue opportunities that meet our strict
requirements for an acceptable risk profile and attractive potential cash flow
returns. If we do not believe that such opportunities are available, we prefer
to reduce our acquisition activities and focus on the optimization of our
existing portfolio rather than pursue growth by accepting greater risks or
inferior returns.

----------------

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

THE EXCHANGE OFFER

On October 4, 2002, we privately placed $200,000,000 aggregate principal
amount of 4.625% senior notes due 2007 and $500,000,000 aggregate principal
amount of 5.875% senior notes due 2012, which we refer to collectively as the
original notes, in a transaction exempt from registration under the Securities
Act. In connection with the private placement, we entered into a registration
rights agreement, dated as of October 1, 2002, with the initial purchasers of
the original notes. In the registration rights agreement, we agreed to offer our
new 4.625% senior notes due 2007 and 5.875% senior notes due 2012, which will be
registered under the Securities Act and which we refer to collectively as the
exchange notes, in exchange for the applicable original notes. The exchange
offer is intended to satisfy our obligations under the registration rights
agreement. We also agreed to deliver this prospectus to the holders of the
original notes. In this prospectus we refer to the original notes and the
exchange notes as the notes. You should read the discussion under the headings
"Summary--Terms of the Notes" and "Description of Notes" for information
regarding the notes.

THE EXCHANGE OFFER.......... This is an offer to exchange $1,000 in
principal amount of exchange notes for each
$1,000 in principal amount of original notes. The
exchange notes are substantially identical to the
original notes, except that the exchange notes
will generally be freely transferable. We believe
that you can transfer the exchange notes without
complying with the registration and prospectus
delivery provisions of the Securities Act if you:

o acquire the exchange notes in the ordinary
course of your business;

o are not and do not intend to become engaged
in a distribution of the exchange notes;

o are not an "affiliate" (within the meaning of
the Securities Act) of ours;

o are not a broker-dealer (within the meaning
of the Securities Act) that acquires the
original notes from us or our affiliates;

o are not a broker-dealer (within the meaning of
the Securities Act) that acquired the original
notes in a transaction as part of its
market-making or other trading activities.

If any of these conditions are not satisfied and
you transfer any exchange note without
delivering a proper prospectus or without
qualifying for a registration exemption, you may
incur liability under the Securities Act. See
"The Exchange Offer--Terms of the Exchange."

REGISTRATION RIGHTS
AGREEMENT................... Under the registration rights agreement, we have
agreed to use our reasonable best efforts to
consummate the exchange offer or cause the
original notes to be registered under the
Securities Act to permit resales. If we are not
in compliance with our obligations under the
registration rights agreement, liquidated damages
will accrue on the original notes in addition to
the interest that is otherwise due on the
original notes. If the exchange offer is
completed on the terms and within the time period
contemplated by this prospectus, no liquidated
damages will be payable on the notes. The
exchange notes will not contain any provisions
regarding the payment of liquidated damages. See
"The Exchange Offer--Liquidated Damages."

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

EXPIRATION DATE............. The exchange offer will expire at 5:00 p.m.,
New York City time, on , 200 , unless we
extend it.

EXCHANGE DATE............... Original notes will be accepted for exchange at
the time when all conditions of the exchange
offer are satisfied or waived. The exchange notes
will be delivered promptly after we accept the
original notes.

CONDITIONS TO THE
EXCHANGE OFFER.............. Our obligation to complete the exchange offer is
subject to certain conditions. See "The Exchange
Offer--Conditions to the Exchange Offer." We
reserve the right to terminate or amend the
exchange offer at any time prior to the
expiration date upon the occurrence of certain
specified events.

WITHDRAWAL RIGHTS........... You may withdraw the tender of your original
notes at any time before the expiration of the
exchange offer on the expiration date. Any
original notes not accepted for any reason will
be returned to you without expense as promptly as
practicable after the expiration or termination
of the exchange offer.

PROCEDURES FOR TENDERING
ORIGINAL NOTES............. See "The Exchange Offer--How to Tender."

UNITED STATES FEDERAL INCOME
TAX CONSEQUENCES........... The exchange of the original notes for exchange
notes by U.S. Holders (as defined below) will not
be a taxable exchange for federal income tax
purposes, and U.S. Holders should not recognize
any taxable gain or loss as a result of such
exchange.

EFFECT ON HOLDERS OF ORIGINAL
NOTES...................... If the exchange offer is completed on the terms
and within the period contemplated by this
prospectus, holders of original notes will have
no further registration or other rights under the
registration rights agreement, except under
limited circumstances. See "The Exchange
Offer--Other."

HOLDERS OF ORIGINAL NOTES WHO DO NOT TENDER
THEIR ORIGINAL NOTES WILL CONTINUE TO HOLD THOSE
ORIGINAL NOTES. ALL UNTENDERED, AND TENDERED BUT
UNACCEPTED, ORIGINAL NOTES WILL CONTINUE TO BE
SUBJECT TO THE TRANSFER RESTRICTIONS PROVIDED
FOR IN THE ORIGINAL NOTES AND THE INDENTURE
UNDER WHICH THE ORIGINAL NOTES HAVE BEEN ISSUED.
To the extent that original notes are tendered
and accepted in the exchange offer, the trading
market, if any, for the original notes could be
adversely affected. See "Risk Factors--Risks
Associated with the Exchange Offer--You may not
be able to sell your original notes if you do
not exchange them for registered exchange notes
in the exchange offer."; "--Your ability to sell
your original notes may be significantly

more limited and the price at which you may be
able to sell your original notes may be
significantly lower if you do not exchange them
for registered exchange notes in the exchange
offer."; and "The Exchange Offer--Other."

USE OF PROCEEDS............. We will not receive any proceeds from the
issuance of exchange notes in the exchange offer.

EXCHANGE AGENT.............. The Bank of New York is serving as the exchange
agent in connection with the exchange offer.

TERMS OF THE NOTES

GENERAL..................... $200,000,000 aggregate principal amount of
4.625% senior notes due October 1, 2007, and
$500,000,000 aggregate principal amount of 5.875%
senior notes due October 1, 2012.

INTEREST PAYMENT DATES...... January 31 and July 31 of each year, commencing
January 31, 2003.

OPTIONAL REDEMPTION......... We may redeem the notes of each series, at our
option, in whole or in part, at any time, at a
redemption price equal to the greater of:

(1) 100% of the principal amount of the notes
to be redeemed; or

(2) the sum of the present values of the
remaining scheduled payments of principal
of and interest on the series of notes to
be redeemed discounted to the date of
redemption on a semiannual basis (assuming
a 360-day year consisting of twelve 30-day
months) at a discount rate equal to the
yield on equivalent Treasury securities
plus 37.5 basis points,

plus, for (1) or (2) above, whichever is
applicable, accrued and unpaid interest, if any,
on such notes to the date of redemption.

SINKING FUND................ The notes are not subject to a mandatory
sinking fund.

CHANGE OF CONTROL........... Upon the occurrence of a Change of Control each
holder of the notes will have the right, at the
holder's option, to require us to repurchase all
or any part of the holder's notes at a purchase
price in cash equal to 101% of the principal
thereof, plus accrued and unpaid interest, if
any, to the date of such purchase in accordance
with the procedures set forth in the indenture
for the notes. A Change of Control means the
occurrence of both of the following: (1) a
transaction pursuant to which Berkshire Hathaway
ceases to own, on a diluted basis, at least a
majority of our common stock, assuming conversion
of all convertible securities then owned by
Berkshire Hathaway, without regard to whether
then presently convertible, or we or our
subsidiaries dispose of all or substantially all
of our property and that of our subsidiaries to
any entity which is not so majority owned by
Berkshire Hathaway, and (2) within 90 days after
the earlier of the announcement or occurrence of
any such transaction, a downgrade in the ratings
for the notes (generally to below investment
grade by both Moody's Investors Service, Inc. and
Standard & Poor's Rating Service) occurs. See
"Description of the Notes--Covenants--Purchase of
Notes Upon a Change of Control."

RANKING..................... The notes are our general, unsecured senior
obligations and rank pari passu in right of
payment with all our other existing and future
senior unsecured obligations and senior in right
of

payment to all our existing and future
subordinated obligations. The notes are
effectively subordinated to all our existing and
future secured obligations and to all existing
and future obligations of our subsidiaries.

COVENANTS................... The indenture for the notes contains covenants
that, among other things, restrict our ability to
grant liens on our assets and our ability to
merge, consolidate or transfer or lease all or
substantially all of our assets. See "Description
of the Notes--Covenants."

EVENTS OF DEFAULT........... Events of default with respect to the notes of
any series under the indenture include, among
other things:

(1) default in the payment of any interest on
any notes of that series for 30 days after
payment is due;

(2) default in the payment of principal of, or
premium, if any, on any note of that
series or as to any payment required in
connection with a Change of Control as
described above;

(3) our failure to perform, or breach by us
of, any covenant contained in the
indenture or the notes of that series,
which failure continues for 30 days after
written notice thereof is provided to us
pursuant to the indenture;

(4) our failure or the failure of any of our
significant subsidiaries (as defined later
in this prospectus) to pay when due beyond
any applicable grace period, or the
acceleration of, debt (other than debt
that is non-recourse to us) in excess of
$100,000,000;

(5) the entry by a court of one or more
judgments against us or any of our
significant subsidiaries (other than a
judgment that is non-recourse to us)
requiring payment by us in an aggregate
amount in excess of $100,000,000 which has
not been vacated, discharged, satisfied or
stayed pending appeal within 60 days from
entry; and

(6) the occurrence of certain events of
bankruptcy, insolvency or reorganization
with respect to us or any of our
significant subsidiaries.

See "Description of the Notes--Definitions" and
"--Events of Default."

RATINGS..................... The notes were initially assigned ratings of
Baa3 by Moody's, BBB-- by S&P and BBB by Fitch,
Inc. However, these ratings are subject to
change at any time.

DENOMINATION AND FORM....... The original notes were, and the exchange notes
will be, issued in denominations of $1,000 and
any integral multiple of $1,000. The original
notes were, and the exchange notes will be,
represented by one or more global securities
registered in the name of The Depository Trust
Company or its nominee.

Beneficial interests in the global securities
representing the original notes are, and the
exchange notes will be, shown on, and transfers
of the beneficial interests in the global
securities representing the original notes are,
and transfers of the beneficial interests in the
global securities representing the exchange
notes will be, effected only through, records
maintained by DTC and its participants. Except
as described later in this prospectus, notes in
certificated form will not be issued. See
"Description of the Notes--Global Notes;
Book-Entry System."

TRUSTEE..................... The Bank of New York is the trustee for the
holders of the notes.

GOVERNING LAW............... The notes, the indenture and the other
documents for the offering of the notes are
governed by the laws of the State of New York.

RISK FACTORS

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

SUMMARY SELECTED HISTORICAL CONSOLIDATED FINANCIAL AND OPERATING DATA

The following table presents our summary historical consolidated financial
and operating data as of and for the years ended December 31, 2001, 2000, and
1999, and as of September 30, 2002 and for the nine months ended September 30,
2002 and 2001. Our unaudited consolidated financial statements as of September
30, 2002 and for the nine months ended September 30, 2002 and 2001 reflect all
adjustments necessary in the opinion of our management (consisting of normal
recurring accruals) for a fair presentation of such data. The financial data set
forth below should be read in conjunction with our historical consolidated
financial statements and the notes thereto appearing elsewhere in this
prospectus. All data (except for ratios) is presented in thousands.

YEAR ENDED
DECEMBER 31,
2001 (1)
--------------------------

STATEMENT OF OPERATIONS DATA:
Operating revenues ........................... $ 5,060,605
Total revenues ............................... 5,336,804
Interest expense, net of capitalized
interest ................................... 412,794
Income before provision for income
taxes ...................................... 503,884
Net income ................................... 142,669 (4)
OTHER FINANCIAL DATA:
Depreciation and amortization ................ $ 538,702
Capital expenditures ......................... 576,752
Ratio of earnings to fixed charges (7) ....... 1.8
Net cash flows from operating activities ..... 846,998
EBITDA (8) ................................... 1,455,380
Adjusted EBITDA (8) .......................... 1,275,887
EBIT (9) ..................................... 916,678
Adjusted EBIT (9) ............................ 737,185

AS OF SEPTEMBER 30,
2002
----------------
BALANCE SHEET DATA:
Property, plant, contracts and
equipment, net ............................. $ 9,168,940
Total assets ................................. 16,984,050
Short-term debt .............................. 642,031
Current portion of long-term debt ............ 483,106
Parent company debt .......................... 1,623,178
Subsidiary and project debt .................. 6,388,169
Total liabilities ............................ 12,247,784
Parent company-obligated mandatorily
redeemable preferred securities held
by Berkshire Hathaway ...................... 1,727,772
Parent company-obligated mandatorily
redeemable preferred securities held
by others .................................. 335,043
Total shareholders' equity ................... 2,491,515

OUR PREDECESSOR
MARCH 14, 2000 -----------------------------------------
THROUGH JANUARY 1, 2000 YEAR ENDED
DECEMBER 31, THROUGH DECEMBER 31,
2000 (2) MARCH 13, 2000 1999 (3)
--------------- ------------------ ----------------------

STATEMENT OF OPERATIONS DATA:
Operating revenues ........................... $4,147,867 $ 1,087,125 $ 4,184,546
Total revenues ............................... 4,242,749 1,106,609 4,466,425
Interest expense, net of capitalized
interest ................................... 311,404 85,814 426,173
Income before provision for income
taxes ...................................... 219,204 91,170 357,069
Net income ................................... 81,257 51,312 (5) 167,230 (6)
OTHER FINANCIAL DATA:
Depreciation and amortization ................ $ 383,351 $ 97,278 $ 427,690
Capital expenditures ......................... 538,729 123,541 603,640
Ratio of earnings to fixed charges (7) ....... 1.3 1.7 1.6
Net cash flows from operating activities ..... 246,407 171,083 554,959
EBITDA (8) ................................... 913,959 274,262 1,210,932
Adjusted EBITDA (8) .......................... 913,959 281,867 1,126,637
EBIT (9) ..................................... 530,608 176,984 783,242
Adjusted EBIT (9) ............................ 530,608 184,589 698,947

OUR PREDECESSOR
---------------------------------------------------
AS OF DECEMBER 31,
2001 2000 1999
----------- ----------- ----------------

BALANCE SHEET DATA:
Property, plant, contracts and
equipment, net ............................. $6,527,448 $ 5,348,647 $ 5,463,329
Total assets ................................. 12,615,333 11,610,939 10,766,352
Short-term debt .............................. 256,012 261,656 379,523
Current portion of long-term debt ............ 317,180 438,978 235,202
Parent company debt .......................... 1,834,498 1,829,971 1,856,318
Subsidiary and project debt .................. 4,754,811 3,388,696 3,642,703
Total liabilities ............................ 9,767,438 8,911,349 8,978,924
Parent company-obligated mandatorily
redeemable preferred securities held
by Berkshire Hathaway ...................... 454,772 454,772 --
Parent company-obligated mandatorily
redeemable preferred securities held
by others .................................. 333,379 331,751 450,000
Total shareholders' equity ................... 1,708,167 1,576,401 994,588

NINE MONTHS ENDED SEPTEMBER 30,
2002 2001
------------------ -----------------

STATEMENT OF OPERATIONS DATA:
Operating revenues .................................... $3,404,533 $3,756,931
Total revenues ........................................ 3,549,744 4,043,075
Interest expense, net of capitalized interest ......... 438,870 290,153
Income before provision for income taxes .............. 492,192 502,729
Net income ............................................ 306,800 (10) 122,085 (11)
OTHER FINANCIAL DATA:
Depreciation and amortization ......................... $ 386,531 $ 395,253
Capital expenditures .................................. 778,750 376,962
Ratio of earnings to fixed charges (7) ................ 1.9 2.1
Net cash flows from operating activities .............. 682,782 790,990
EBITDA (8) ............................................ 1,317,593 1,188,135
Adjusted EBITDA (8) ................................... 1,263,253 967,027
EBIT (9) .............................................. 931,062 792,882
Adjusted EBIT (9) ..................................... 876,722 571,774

- ----------

(1) Reflects the acquisition of the Yorkshire Electricity electricity
distribution business and the simultaneous sale of the Northern Electric
electricity and gas supply business on September 21, 2001.

(2) Reflects our acquisition by a private investor group on March 14, 2000.

(3) Reflects our acquisition of MidAmerican Energy on March 12, 1999, our
disposition of the Coso Joint Ventures on February 26, 1999, and our
disposition of a 50% ownership interest in CE Generation, LLC, or CE Gen,
on March 3, 1999.

(4) Includes $15.2 million of non-recurring net income related to the sale of
the Northern Electric electricity and gas supply business, the sale of the
Telephone Flat Project, the sale of Western States Geothermal, the transfer
of Bali Energy Ltd. shares, and the Teesside Power Limited, or TPL, asset
valuation impairment charge.

(5) Includes $7.6 million of net non-recurring expenses for the costs related
to our acquisition by a private investor group on March 14, 2000.

(6) Includes $81.5 million of non-recurring net income related to the
settlement of political risk insurance proceeds related to our investment
in Indonesia, gains on sales of shares of McLeodUSA, our disposition of the
Coso Joint Ventures, our disposition of a 50% ownership interest in CE Gen,
CE Electric UK restructuring charges and transaction costs related to our
acquisition by a private investor group.

(7) For purposes of calculating the ratio of earnings to fixed charges,
earnings are divided by fixed charges. Earnings represent the aggregate of
(a) our pre-tax income and (b) fixed charges, less capitalized interest.
Fixed charges represent interest (whether expensed or capitalized),
amortization of deferred financing and bank fees, and the estimated
interest component of rentals.

(8) EBITDA represents earnings before interest, taxes, depreciation, and
amortization. Adjusted EBITDA represents EBITDA adjusted for non-recurring
income and expense items as follows:

(a) items discussed in (4), which are $179.4 million before tax;

(b) item discussed in (5);

(d) items discussed in (10), which are $54.3 million before tax; and

(e) items discussed in (11), which are $221.1 million before tax.

Information concerning EBITDA and adjusted EBITDA is presented not as a
measure of operating results, but rather as a measure of our ability to
service debt. EBITDA and adjusted EBITDA

should not be construed as an alternative to either (a) operating income
(determined in accordance with generally accepted accounting principles, or
GAAP) or (b) cash flow from operating activities (determined in accordance
with GAAP) . Since EBITDA and adjusted EBITDA are not defined by GAAP, they
may not be calculated on the same basis as similarly titled measures of
other companies.

(9) EBIT represents earnings before interest and taxes. Adjusted EBIT
represents EBIT adjusted for non-recurring income and expense items.
Information concerning EBIT and adjusted EBIT is presented not as a measure
of operating results, but rather as a measure of our ability to service
debt. EBIT and adjusted EBIT should not be construed as an alternative to
either (a) operating income (determined in accordance with GAAP) or (b)
cash flow from operating activities (determined in accordance with GAAP).
Since EBIT and adjusted EBIT are not defined by GAAP, they may not be
calculated on the same basis as similarly titled measures of other
companies.

(10) Includes $41.3 million of non-recurring net income related to the sale of
assets by CalEnergy Gas (Holdings) Limited, or CE Gas Holdings.

(11) Includes $13.7 million of non-recurring net income related to the sale of
Western States Geothermal and the sale of the Northern Electric electricity
and gas supply business, or Northern Supply.

RISK FACTORS

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

RISK ASSOCIATED WITH OUR CORPORATE AND FINANCIAL STRUCTURE

WE ARE A HOLDING COMPANY THAT DEPENDS ON DISTRIBUTIONS FROM OUR
SUBSIDIARIES AND JOINT VENTURES TO MEET OUR NEEDS.

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

o their earnings and capital requirements,

o the satisfaction of various covenants and conditions contained in
financing documents by which they are bound or in their organizational
documents, and

o in the case of our regulated utility subsidiaries, regulatory
restrictions which restrict their ability to distribute profits to us.

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

WE ARE SUBSTANTIALLY LEVERAGED AND THE NOTES ARE STRUCTURALLY SUBORDINATED
TO THE INDEBTEDNESS OF OUR SUBSIDIARIES.

Our substantial leverage level presents the risk that we might not generate
sufficient cash to service our indebtedness, including the notes, or that our
leveraged capital structure could limit our ability to finance future
acquisitions, develop additional projects, compete effectively and operate
successfully under adverse economic conditions. At September 30, 2002, our
outstanding indebtedness was approximately $2.0 billion (excluding $2.1 billion
in aggregate principal amount of our trust preferred securities, our guarantees
and letters of credit in respect of subsidiary indebtedness aggregating
approximately $235 million and our completion guarantee issued in favor of the
lenders under Kern River's $875 million construction loan facility in connection
with Kern River's 2003 Expansion Project). In addition, our subsidiaries have
significant amounts of indebtedness. At September 30, 2002, our consolidated
subsidiaries' and joint ventures' total outstanding indebtedness was
approximately $7.1 billion, which does not include $453 million, representing
our share of outstanding indebtedness of CE Generation, LLC, or CE Gen. This
amount also does not include trade debt of our subsidiaries. The terms of the
notes do not limit our ability or the ability of our subsidiaries or joint
ventures to incur additional debt or issue additional preferred stock. Claims of
creditors of our subsidiaries and joint ventures have priority over your claims
with respect to the assets and earnings of our subsidiaries and joint ventures.
In addition, the stock or assets of substantially all of our operating
subsidiaries and joint ventures is directly or indirectly pledged to secure
their financings and, therefore, may be unavailable as potential sources of
repayment of the notes.

RISKS ASSOCIATED WITH OUR BUSINESS

OUR RECENT GROWTH HAS BEEN ACHIEVED, IN PART, THROUGH STRATEGIC
ACQUISITIONS, AND ADDITIONAL ACQUISITIONS MAY NOT BE SUCCESSFUL.

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

In the past six years, we have completed several significant acquisitions,
including the acquisitions of Northern Electric, Yorkshire Electricity,
MidAmerican Energy, Kern River and Northern Natural Gas. We have successfully
integrated Northern Electric, Yorkshire Electricity, MidAmerican Energy and Kern
River. We closed on the Northern Natural Gas acquisition in August 2002 and are
in the process of integrating its operations. We intend to continue to actively
pursue acquisitions in the energy industry to complement and diversify our
existing business for the foreseeable future.

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

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

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

WE ARE ACTIVELY PURSUING, DEVELOPING AND CONSTRUCTING NEW OR EXPANDED
FACILITIES, THE COMPLETION AND EXPECTED COST OF WHICH IS SUBJECT TO SIGNIFICANT
RISK.

Through our operating subsidiaries, we are continuing to develop,
construct, own and operate new or expanded facilities, including Kern River's
2003 Expansion Project, the Zinc Recovery Project and two planned electric
generating plants in Iowa, and in the future we expect to pursue the
development, construction, ownership and operation of additional new or expanded
energy projects (including, without limitation, generation, distribution,
transmission, exploration/production, storage and supply projects and related
activities, infrastructure and services), both domestically and internationally,
the completion of any of which, including any future projects, is subject to
substantial risk and may expose us to significant costs. We cannot assure you
that our development or construction efforts on any particular project, or our
efforts generally, will be successful.

Also, a proposed expansion or project may cost more than planned to
complete, and such excess costs, if related to a regulated asset and found to be
imprudent, may not be recoverable in rates. The inability to successfully and
timely complete a project or avoid unexpected costs may require us to perform
under guarantees (such as the Kern River completion guarantee), and the
inability to avoid unsuccessful projects or to recover any excess costs may
materially affect our ability to service our obligations under the notes. Our
Kern River completion guarantee also contains a potential acceleration event
based on our credit ratings and certain other potential acceleration events
which are more fully described elsewhere in this prospectus.

OUR SUBSIDIARIES ARE SUBJECT TO CERTAIN OPERATING UNCERTAINTIES WHICH MAY
ADVERSELY AFFECT REVENUES, EXPENSES OR DISTRIBUTIONS.

The operation of complex electric and gas utility (including transmission
and distribution systems), pipeline or power generating facilities involves many
operating uncertainties and events beyond our control. Operating risks include
the breakdown or failure of power generation equipment, compressors, pipelines,
transmission and distribution lines or other equipment or processes, fuel
interruption, performance below expected levels of output, capacity or
efficiency, operator error and catastrophic events such as severe storms, fires,
earthquakes or explosions. A casualty occurrence might result in injury or loss
of life, extensive property damage or environmental damage. Revenues, expenses
and distributions may also be adversely affected by general economic, business,
regulatory and weather conditions. The realization of any of these risks could
significantly reduce or eliminate our affiliates' revenues or significantly
increase our affiliates' expenses, thereby adversely affecting the ability to
receive distributions from subsidiaries and joint ventures.

We currently possess property, business interruption, catastrophic and
general liability insurance, but proceeds from such insurance coverage may not
be adequate for all liabilities incurred, lost revenue or increased expenses.
Moreover, such insurance may not be available in the future at commercially
reasonable costs and on commercially reasonable terms. Changes in the insurance
markets subsequent to the September 11, 2001 terrorist attacks have made it more
difficult for us to obtain certain types of coverage. There can be no assurance
that we will be able to obtain the levels or types of insurance we would
otherwise have obtained prior to these market changes or that the insurance
coverage we do obtain will not contain large deductibles or fail to cover
certain hazards or that it will otherwise cover all potential losses.

ACTS OF SABOTAGE AND TERRORISM AIMED AT OUR FACILITIES COULD ADVERSELY
EFFECT OUR BUSINESS.

Since the September 11, 2001 terrorist attacks, the United States
government has issued warnings that energy assets, specifically our nation's
pipeline and utility infrastructure, may be the future targets of terrorist
organizations. These developments have subjected our operations to increased
risks. Any future acts of sabotage or terrorism aimed at our facilities, or
those of our customers, could have a material adverse effect on our business,
financial condition, results of operations and ability to service the notes. Any
resulting acts of war or the threat of war as a result of such terrorist attacks
could adversely affect the economy and energy consumption. Instability in the
financial markets as a result of terrorism or war could also materially
adversely affect our ability to raise capital.

WE ARE SUBJECT TO COMPREHENSIVE ENERGY REGULATION AND CHANGES IN
REGULATION AND RATES MAY ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION,
RESULTS OF OPERATIONS AND ABILITY TO SERVICE THE NOTES.

We are subject to comprehensive governmental regulation, including
regulation in the United States by various federal, state and local regulatory
agencies, regulation in the United Kingdom and regulation in the Philippines,
all of which significantly influences our operating environment, our rates, our
capital structure, our costs and our ability to recover our costs from
customers. These regulatory agencies include, among others, the Federal Energy
Regulatory Commission, or the FERC, the Environmental Protection Agency, or the
EPA, the Nuclear Regulatory Commission, the United States Department of
Transportation, the Iowa Utilities Board, or the IUB, the Illinois Commerce
Commission, other state utility boards, numerous local agencies, the Gas and
Electricity Markets Authority, or GEMA, which in discharging certain of its
powers acts through its staff within the Office of Gas and Electricity Markets,
or Ofgem, in

the United Kingdom, and various other governmental agencies in the United
Kingdom and the Philippines. The FERC has jurisdiction over, among other things,
wholesale rates for electric transmission service and electric energy sold in
interstate commerce, interstate natural gas transportation and storage rates,
the siting and construction of interstate natural gas transportation facilities
and certain other activities of our utility subsidiaries. United States federal,
state and local agencies also have jurisdiction over many of our other
activities. The utility commissions in the states where our utility subsidiaries
operate regulate many aspects of our utility operations including siting and
construction of facilities, customer service and the rates that we can charge
customers. The revenues of our United Kingdom distribution businesses are
subject to review and adjustment by GEMA and many other aspects of our
subsidiaries' United Kingdom operations are subject to the jurisdiction of GEMA
and other regulators and agencies in the United Kingdom.

The structure of federal and state energy regulation is currently
undergoing change and has in the past, and may in the future, be the subject of
various challenges, initiatives and restructuring proposals by policy makers,
utilities and other industry participants. In addition to Congressional
initiatives, many states are implementing or considering regulatory initiatives
designed to increase competition in the domestic power generation industry and
increase access to electric utilities' transmission and distribution systems for
independent power producers and electricity consumers. The implementation of
regulatory changes in response to such challenges, initiatives and restructuring
proposals could result in the imposition of more comprehensive or stringent
requirements on us or our subsidiaries or other industry participants, which
would result in increased compliance costs and could have a material adverse
effect on our business, financial condition, results of operations and ability
to service the notes.

We are unable to predict the impact on our operating results from the
future regulatory activities of any of these agencies or the Securities and
Exchange Commission, or SEC, under the Public Utility Holding Company Act of
1935, as amended, or PUHCA. Changes in regulations or the imposition of
additional regulations could have a material adverse impact on our results of
operations. Recent developments, events and uncertainties which have impacted or
could impact our businesses are described below.

On July 31, 2002, the FERC issued a notice of proposed rulemaking with
respect to Standard Market Design for the electric industry. The FERC has
characterized the proposal as portending "sweeping changes" to the use and
expansion of the interstate transmission and wholesale bulk power systems in the
United States. The proposal includes numerous proposed changes to the current
regulation of transmission and generation facilities designed "to promote
economic efficiency" and replace the "obsolete patchwork we have today,"
according to the FERC Chairman. The final rule, if adopted as currently
proposed, would require all public utilities operating transmission facilities
subject to the FERC jurisdiction to file revised open access transmission
tariffs that would require changes to the basic services these public utilities
currently provide. The proposed rule may impact the pricing of MidAmerican
Energy's electricity and transmission products. The FERC does not envision that
a final rule will be fully implemented until September 30, 2004. We are still
evaluating the proposed rule, and we believe that the final rule could vary
considerably from the initial proposal. Accordingly, we are presently unable to
quantify the likely impact of the proposed rule on us.

The state utility regulatory environment has to date, in general, given
MidAmerican Energy an exclusive right to serve retail electricity customers
within its primary service territory in Iowa and, in turn, the obligation to
provide electric service to those customers. There can be no assurance that
there will not be a change in legislation or regulation in Iowa or in any of the
other states in which we operate to allow retail competition in MidAmerican
Energy's service territory.

Because our Kern River and Northern Natural Gas pipeline systems are
interstate natural gas pipelines subject to regulation as natural gas companies
under the Natural Gas Act, as amended, the rates we can charge our customers and
other terms and conditions of service are subject to review by the FERC and the
possibility of modification in periodic rate proceedings or at any time in
response to a complaint proceeding initiated by a customer or on the FERC's own
initiative. The rates we can charge are required to be just and reasonable. The
objective of the rate setting process is to allow us to recover our costs to

construct, own, operate and maintain our pipelines which are actually and
prudently incurred and to afford us an opportunity to earn a reasonable rate of
return. Under the terms of our transportation service contracts and in
accordance with the FERC's rate making principles, our current maximum tariff
rates are designed to recover costs included in our pipeline systems' regulatory
cost of service that are associated with the construction and operation of our
pipeline systems that are actually, reasonably and prudently incurred. All costs
incurred may not be recoverable through existing or future rates. Failure to
recover material costs may have a material adverse effect on our business,
financial condition, results of operations and ability to service the notes.

Revenue from Northern Electric's and Yorkshire Electricity's distribution
business is controlled by a distribution price control formula which determines
the maximum average price per unit of electricity that a distribution network
operator in Great Britain may charge. The distribution price control formula is
expected to have a five-year duration and is subject to review by the British
regulatory body for the energy sector, GEMA, at the end of each five-year period
and at other times in the discretion of GEMA. At each review, GEMA can propose
adjustments to the distribution price control formula. In December 1999, a
review resulted in a reduction in allowed revenue of 24% for Northern Electric's
distribution business and 23% for Yorkshire Electricity's distribution business,
in real terms, with effect from and after April 1, 2000. The next review of the
distribution price control formula is expected to become effective in April
2005. Any further price reviews by GEMA, including those it may elect to conduct
at any time in its discretion, may have a material adverse effect on our results
of operations.

The Philippine Congress has passed the Electric Power Reform Act of 2001,
which is aimed at restructuring the power industry, including privatization of
the National Power Corporation, or the NPC, and introduction of a competitive
electricity market, among other initiatives. The implementation of the bill may
have an adverse impact on our future operations in the Philippines and the
Philippines power industry as a whole.

WE ARE SUBJECT TO ENVIRONMENTAL, SAFETY AND OTHER LAWS AND REGULATIONS
WHICH MAY ADVERSELY IMPACT US.

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

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

Potential pipeline safety legislation and an increase in public
expectations on pipeline safety may also require replacement of some of our
pipeline segments, addition of monitoring equipment, and more frequent
inspection or testing of our pipeline facilities. These requirements coupled
with increases in state and federal agency oversight, if adopted, would
necessitate additional testing and reporting which may result in higher
operating costs and/or capital costs. Our FERC-approved tariffs or competition
from other natural gas sources may not allow us to recover these increased costs
of compliance.

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

Any failure to recover increased environmental or safety costs incurred by
us may have a material adverse effect on our business, financial condition,
results of operations and ability to service the notes.

INCREASED COMPETITION RESULTING FROM LEGISLATIVE, REGULATORY AND
RESTRUCTURING EFFORTS COULD HAVE A SIGNIFICANT FINANCIAL IMPACT ON US AND OUR
UTILITY SUBSIDIARIES AND CONSEQUENTLY DECREASE OUR REVENUE.

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

The generation segment of the electric industry has been and will be
significantly impacted by competition. The introduction of competition in the
wholesale market has resulted in a proliferation of power marketers and a
substantial increase in market activity. Many of these marketers have
experienced financial difficulties and the market continues to be volatile.

As retail competition continues to evolve, margins will be pressured by
competition from other utilities, power marketers and self-generation. Many
states and the federal government are implementing or considering regulatory
initiatives that would increase access to electric utilities' transmission and
distribution systems for independent power producers, utilities, power marketers
and electricity customers. Although the recent and anticipated changes in the
United States electric utility industry may create opportunities, they will also
create additional challenges and risks for utilities. Competition will put
pressure on margins for traditional electric services. Illinois recently enacted
a law that provides for full retail customer choice in 2002. While introduction
of retail competition in Iowa is not presently expected, depending upon the
terms of any such legislation, if introduced it could have a material adverse
effect on us. These types of restructurings and other industry restructuring
efforts could materially impact our results of operations in a manner which is
difficult to predict, since such efforts will depend on the terms and timing of
such restructuring.

As a result of the FERC orders, including Order 636, the FERC's policies
favoring competition in gas markets, the expansion of existing pipelines and the
construction of new pipelines, the interstate pipeline industry has begun to
experience some failure to renew, or turn back, of firm capacity, as existing
transportation service agreements expire and are terminated. Local distribution
companies and end-use customers have more choices in the new, more competitive
environment and may be able to obtain service from more than one pipeline to
fulfill their natural gas delivery requirements. If a pipeline experiences
capacity turn back and is unable to remarket the capacity, the pipeline or its
remaining customers may have to bear the costs associated with the capacity that
is turned back. Any new pipelines that are constructed could compete with our
pipeline subsidiaries for customers' service needs. Increased

competition could reduce the volumes of gas transported by our pipeline
subsidiaries or, in cases where they do not have long-term fixed rate contracts,
could force our pipeline subsidiaries to lower their rates to meet competition.
This could adversely affect our pipeline subsidiaries' financial results.

A SIGNIFICANT DECREASE IN DEMAND FOR NATURAL GAS IN THE MARKETS SERVED BY
OUR SUBSIDIARIES' PIPELINE AND DISTRIBUTION SYSTEMS WOULD SIGNIFICANTLY DECREASE
OUR REVENUE AND THEREBY ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION,
RESULTS OF OPERATIONS AND ABILITY TO SERVICE THE NOTES.

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

o a recession or other adverse economic condition that results in a
lower level of economic activity or reduced spending by consumers on
natural gas;

o an increase in the market price of natural gas or a decrease in the
price of other competing forms of energy, including electricity, coal
and fuel oil;

o higher fuel taxes or other governmental or regulatory actions that
increase, directly or indirectly, the cost of natural gas or that
limit the use of natural gas;

o a shift by consumers to more fuel-efficient or alternative fuel
machinery or an improvement in fuel economy, whether as a result of
technological advances by manufacturers, pending legislation proposing
to mandate higher fuel economy, or otherwise; and

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

FAILURE OF OUR SIGNIFICANT POWER PURCHASERS AND PIPELINE CUSTOMERS TO PAY
AMOUNTS DUE UNDER THEIR CONTRACTS COULD REDUCE OUR REVENUES MATERIALLY.

Our subsidiaries' non-utility generating facilities and both of our
pipeline subsidiaries are dependent upon a relatively small number of customers
for a significant portion of their revenues. As a result, our profitability and
ability to make payments under the notes generally will depend upon the
continued financial performance and creditworthiness of these customers.
Accordingly, failure of one or more of our most significant customers to pay for
contracted electric generating capacity or pipeline capacity reservation
charges, for reasons related to financial distress or otherwise, could reduce
our revenues materially if we were not able to make adequate alternate
arrangements and therefore could have a material adverse effect on our business,
financial condition, results of operations and ability to service the notes.

OUR PIPELINE SUBSIDIARIES MAY NOT BE ABLE TO MAINTAIN OR REPLACE LONG-TERM
GAS TRANSPORTATION SERVICE AGREEMENTS AT FAVORABLE RATES AS EXISTING CONTRACTS
EXPIRE.

Our business, financial condition, results of operations and ability to
service the notes are dependent in significant part on the ability of Kern River
and Northern Natural Gas to maintain long-term transportation service agreements
with customers subject to favorable transportation rates.

Many of our long-term transportation service agreements will expire before
the maturity of the notes. Upon expiration, existing customers may elect not to
extend their contracts at rates favorable to our subsidiaries or on a long-term
basis, or at all. Our pipeline subsidiaries may also be unable to obtain
favorable replacement agreements with other customers. The extension or
replacement of the existing long-term contracts depends on a number of factors
beyond our control, including:

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

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

o new pipelines or expansions potentially serving the same markets as
our pipelines;

o the growth in demand for natural gas in the upper Midwest and southern
California;

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

o whether our business strategy, including our expansion strategy,
continues to be successful.

Any failure to extend or replace a significant portion of these contracts
may have a material adverse effect on our business, financial condition, results
of operations and ability to service the notes.

OUR UTILITY AND NON-UTILITY BUSINESSES ARE SUBJECT TO MARKET AND CREDIT
RISK.

We are exposed to market and credit risks in our subsidiaries' generation,
retail distribution and pipeline operations. Specifically, such risks include
commodity price changes, market supply shortages, interest rate changes and
counterparty default. In Iowa, MidAmerican Energy does not have an ability to
pass through fuel price increases in its rates (an energy adjustment clause), so
any significant increase in fuel costs or purchased power costs could have a
negative impact on MidAmerican Energy. To minimize these risks, we require
collateral to be posted if the creditworthiness of counterparties deteriorates
below established levels and enter into financial derivative instrument
contracts to hedge purchase and sale commitments, fuel requirements and
inventories of natural gas, electricity, coal and emission allowances. However,
financial derivative instrument contracts do not eliminate the risk. The impact
of these risks could result in our inability to fulfill contractual obligations,
significantly higher energy or fuel costs relative to corresponding sales
contracts or increased interest expense.

WE HAVE SIGNIFICANT OPERATIONS OUTSIDE THE UNITED STATES WHICH MAY BE
SUBJECT TO INCREASED RISK BECAUSE OF THE ECONOMIC OR POLITICAL CONDITIONS OF THE
COUNTRY IN WHICH THEY OPERATE.

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

Our international projects may be subject to the risk of being delayed,
suspended or terminated by the applicable foreign governments or may be subject
to the risk of contract abrogation, expropriations or other uncertainties
resulting from changes in government policy or personnel or changes in general
political or economic conditions affecting the country. In this regard,
reference is made to the substantial uncertainties associated with one of our
non-utility power projects in the Philippines, which is referred to as the
Casecnan Project, where certain payments under the primary project agreement are
currently not being made by the government of the Philippines and are presently
the subject of international arbitration. Specifically, under the terms of a
Casecnan Project agreement between CE Casecnan Water and Energy Company, Inc.,
or CE Casecnan, and the Philippine National Irrigation Administration, or NIA,
NIA has the option of timely reimbursing CE Casecnan directly for certain taxes
CE Casecnan has

paid. If NIA does not so reimburse CE Casecnan, the taxes paid by CE Casecnan
result in an increase in the Water Delivery Fee under the Casecnan Project
agreement. The payment of certain other taxes by CE Casecnan results
automatically in an increase in the Water Delivery Fee. As of June 30, 2002, CE
Casecnan has paid approximately $54.4 million in taxes which as a result of the
foregoing provisions had resulted in an increase in the Water Delivery Fee. NIA
has failed to pay the portion of the Water Delivery Fee each month which relates
to the payment of these taxes by CE Casecnan. As a result of this non-payment,
on August 19, 2002, CE Casecnan filed a Request for Arbitration against NIA,
seeking payment of such portion of the Water Delivery Fee and enforcement of the
relevant provision of the Casecnan Project agreement going forward. The
arbitration will be conducted in accordance with the rules of the International
Chamber of Commerce.

WE FACE EXCHANGE RATE RISK.

Payments from some of our foreign investments, including without limitation
Northern Electric and Yorkshire Electricity, are made in a foreign currency and
any dividends or distributions of earnings in respect of such investments may be
significantly affected by fluctuations in the exchange rate between the United
States dollar and the British pound or other applicable foreign currency.
Although we may enter into certain transactions to hedge risks associated with
exchange rate fluctuations, there can be no assurance that such transactions
will be successful in reducing such risks.

RISKS ASSOCIATED WITH THE EXCHANGE OFFER

YOU MAY NOT BE ABLE TO SELL YOUR ORIGINAL NOTES IF YOU DO NOT EXCHANGE
THEM FOR REGISTERED EXCHANGE NOTES IN THE EXCHANGE OFFER.

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

o registered under the Securities Act;

o offered or sold under an exemption from the Securities Act and
applicable state securities laws; or

o offered or sold in a transaction not subject to the Securities Act and
applicable state securities laws.

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

YOUR ABILITY TO SELL YOUR ORIGINAL NOTES MAY BE SIGNIFICANTLY MORE LIMITED
AND THE PRICE AT WHICH YOU MAY BE ABLE TO SELL YOUR ORIGINAL NOTES MAY BE
SIGNIFICANTLY LOWER IF YOU DO NOT EXCHANGE THEM FOR REGISTERED EXCHANGE NOTES IN
THE EXCHANGE OFFER.

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

THERE ARE STATE SECURITIES LAW RESTRICTIONS ON THE RESALE OF THE EXCHANGE
NOTES.

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

WE WILL NOT ACCEPT YOUR ORIGINAL NOTES FOR EXCHANGE IF YOU FAIL TO FOLLOW
THE EXCHANGE OFFER PROCEDURES AND, AS A RESULT, YOUR ORIGINAL NOTES WILL
CONTINUE TO BE SUBJECT TO EXISTING TRANSFER RESTRICTIONS AND YOU MAY NOT BE ABLE
TO SELL YOUR ORIGINAL NOTES.

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

FORWARD-LOOKING STATEMENTS

This prospectus contains statements that do not directly or exclusively
relate to historical facts. These statements are "forward-looking statements"
within the meaning of the Private Securities Litigation Reform Act of 1995. You
can typically identify forward-looking statements by the use of forward-looking
words, such as "may", "will", "could", "project", "believe", "anticipate",
"expect", "estimate", "continue", "potential", "plan", "forecast" and similar
terms. These statements represent our intentions, plans, expectations and
beliefs and are subject to risks, uncertainties and other factors. Many of these
factors are outside our control and could cause actual results to differ
materially from such forward-looking statements. These factors include, among
others:

o general economic and business conditions in the jurisdictions in which
our facilities are located;

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

o weather effects on sales and revenues;

o general industry trends;

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

o fuel and power costs and availability;

o continued availability of accessible gas reserves;

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

o availability, term and deployment of capital;

o availability of qualified personnel;

o risks relating to nuclear generation;

o financial or regulatory accounting principles or policies imposed by
the Public Company Accounting Oversight Board, the Financial
Accounting Standards Board, the SEC, the FERC and similar entities
with regulatory oversight; and

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

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

USE OF PROCEEDS

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

The net proceeds of the private placement of the original notes were
approximately $694 million after deducting the initial purchasers' discount and
expenses related to the offering of the original notes. We used these net
proceeds for general corporate purposes, including to repay our short term debt
in the amount of $167 million; and to make up to $300 million of funds available
for an equity contribution to Kern River, to be applied by Kern River to fund a
portion of the costs of its 2003 Expansion Project.

We also used the net proceeds to make an equity contribution of $150
million to Northern Natural Gas and a loan of $300 million to Northern Natural
Gas. Northern Natural Gas used these amounts to repay an equal amount of its
outstanding indebtedness under its bank credit agreement. Northern Natural Gas
repaid the loan to us from the proceeds of its offering of $300 million of
5.375% Senior Notes due 2012, which was completed on October 15, 2002.

THE EXCHANGE OFFER

PURPOSE OF THE EXCHANGE OFFER

On October 4, 2002, we privately placed the original notes in a transaction
exempt from registration under the Securities Act. Accordingly, the original
notes may not be reoffered, resold or otherwise transferred in the United States
unless so registered or unless an exemption from the Securities Act registration
requirements is available. Pursuant to a registration rights agreement with the
initial purchasers of the original notes, we agreed, for the benefit of holders
of the notes, to:

o prepare and file an exchange offer registration statement with the SEC
with respect to a registered offer to exchange each series of original
notes for a series of exchange notes that will be issued under the
same indenture, in the same aggregate principal amount as and with
terms that are substantially identical in all material respects to the
original notes except that they will not contain terms with respect to
transfer restrictions;

o use our reasonable best efforts to cause the exchange offer
registration statement to become effective under the Securities Act
within 270 days after the date on which we issued the original notes;
and

o promptly after the exchange offer registration statement is declared
effective, offer the exchange notes in exchange for surrender of the
original notes.

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

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

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

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

TERMS OF THE EXCHANGE

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

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

registration and prospectus delivery provisions of the Securities Act. However,
if you are an "affiliate" (within the meaning of the Securities Act) of ours or
you intend to participate in the exchange offer for the purpose of distributing
the exchange notes or you are a broker-dealer (within the meaning of the
Securities Act) that acquired notes in a transaction other than as part of its
market-making or other trading activities and who has arranged or has an
understanding with any person to participate in the distribution of the exchange
notes, you:

(1) will not be able to rely on the interpretations by the staff of the
SEC set forth in the above-mentioned no-action letters;

(2) will not be able to tender your notes in the exchange offer; and

(3) must comply with the registration and prospectus delivery requirements
of the Securities Act in connection with any sale or transfer of your
notes unless such sale or transfer is made pursuant to an exemption
from such requirements.

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

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

SHELF REGISTRATION STATEMENT

If:

o we are not permitted to effect the exchange offer because of any
change in law or in applicable interpretations of such law by the
staff of the SEC;

o the exchange offer is not consummated by the 40th day after the date
on which the exchange offer registration statement was declared
effective;

o any of the initial purchasers of the original notes so requests with
respect to the original notes not eligible to be exchanged for
exchange notes in the exchange offer and held by it following the
consummation of exchange offer;

o any holder of notes (other than a broker-dealer electing to exchange
original notes acquired for its own account as a result of
market-making or other trading activities for exchange securities) is
not eligible to participate in the exchange offer and any such holder
so requests for any reason other than the failure by such holder to
make a timely and valid tender in accordance with the terms of
exchange offer; or

o any holder of notes (other than a broker-dealer electing to exchange
original notes acquired for its own account as a result of
market-making or other trading activities for exchange securities)

participates in the exchange offer but does not receive freely
tradeable exchange notes on the date of the exchange and any such
holder so requests for any reason other than the failure by such
holder to make a timely and valid tender in accordance with the terms
of exchange offer,

we will:

o as promptly as practicable prepare and file with the SEC a shelf
registration statement relating to the offer and sale of notes that
are not otherwise freely tradable; and

o use our reasonable best efforts to cause the shelf registration
statement to be declared effective not later than the later to occur
of the date that is 150 days after the date on which our obligation to
file the shelf registration arises or 270 days after the date on which
we issued the original notes; and

o use our reasonable best efforts to keep the shelf registration
statement continuously effective until the earlier of two years from
the date on which we issued the original notes (subject to extension
under certain circumstances) and such shorter period ending when all
the notes covered by the shelf registration statement have been sold
pursuant to the shelf registration statement or are no longer
restricted securities (as defined in Rule 144 under the Securities
Act).

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

LIQUIDATED DAMAGES

A registration default will be deemed to have occurred if:

(1) the exchange offer registration statement is not declared effective
within 270 days after the date on which we issued the original notes;

(2) the shelf registration statement is not declared effective by the
later to occur of the date that is 150 days after the date on which
our obligation to file the shelf registration arises or 270 days after
the date on which we issued the original notes; or

(3) after either the exchange offer registration statement or the shelf
registration statement is declared effective, such registration
statement or the related prospectus thereafter ceases to be effective
or usable (subject to certain exceptions) in connection with resales
of original notes or exchange notes for the periods specified and in
accordance with the registration rights agreement.

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

EXPIRATION DATE; EXTENSIONS; TERMINATION; AMENDMENTS

The exchange offer expires on the expiration date. The expiration date is
5:00 p.m., New York City time, on , 200 , unless we in our sole
discretion extend the period during which the exchange offer is open, in which
event the expiration date is the latest time and date on which the exchange
offer, as so extended by us, expires. We reserve the right to extend the
exchange offer at any time and from time to time prior to the expiration date
by giving written notice to The Bank of New York, as the exchange agent, and by
timely public announcement communicated in accordance with applicable law or
regulation. During any extension of the exchange offer, all original notes
previously tendered pursuant to the exchange offer and not validly withdrawn
will remain subject to the exchange offer.

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

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

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

HOW TO TENDER

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

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

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

Any beneficial owner whose original notes are registered in the name of a
broker, dealer, commercial bank, trust company or other nominee and who wishes
to tender original notes should contact such holder promptly and instruct such
holder to tender original notes on such beneficial owner's behalf. If such
beneficial owner wishes to tender such original notes himself, such beneficial
owner must, prior to completing and executing the letter of transmittal and
delivering such original notes, either make appropriate arrangements to register
ownership of the original notes in such beneficial owner's name or follow the
procedures described in the immediately preceding paragraph. The transfer of
record ownership may take considerable time.

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

THE METHOD OF DELIVERY OF ORIGINAL NOTES AND ALL OTHER DOCUMENTS IS AT YOUR
ELECTION AND RISK. IF SENT BY MAIL, WE RECOMMEND THAT YOU USE REGISTERED MAIL,
RETURN RECEIPT REQUESTED, OBTAIN PROPER INSURANCE, AND COMPLETE THE MAILING
SUFFICIENTLY IN ADVANCE OF THE EXPIRATION DATE TO PERMIT DELIVERY TO THE
EXCHANGE AGENT ON OR BEFORE THE EXPIRATION DATE.

Unless an exemption applies under the applicable law and regulations
concerning "backup withholding" of federal income tax, the exchange agent will
be required to withhold, and will withhold, 31% of the gross proceeds otherwise
payable to a holder pursuant to the exchange offer if the holder does not
provide its taxpayer identification number (social security number or employer
identification number) and certify that such number is correct. Each tendering
holder should complete and sign the main signature form and the Substitute Form
W-9 included as part of the letter of transmittal, so as to provide the
information and certification necessary to avoid backup withholding, unless an
applicable exemption exists and is proved in a manner satisfactory to us and the
exchange agent.

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

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

All questions as to the validity, form, eligibility (including time of
receipt) and acceptance for exchange of any tender of original notes will be
determined by us and our determination will be final and binding. We reserve the
absolute right to reject any or all tenders not in proper form or the
acceptances for exchange of which may, in the opinion of our counsel, be
unlawful. We also reserve the absolute right

to waive any of the conditions of the exchange offer or any defect or
irregularities in tenders of any particular holder whether or not similar
defects or irregularities are waived in the case of other holders. None of us,
the exchange agent or any other person will be under any duty to give
notification of any defects or irregularities in tenders or shall incur any
liability for failure to give any such notification. Our interpretation of the
terms and conditions of the exchange offer (including the letters of transmittal
and the instructions thereto) will be final and binding.

TERMS AND CONDITIONS OF THE LETTERS OF TRANSMITTAL

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

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

See "--Terms of the Exchange."

WITHDRAWAL RIGHTS

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

ACCEPTANCE OF ORIGINAL NOTES FOR EXCHANGE; DELIVERY OF EXCHANGE NOTES

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

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

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

CONDITIONS TO THE EXCHANGE OFFER

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

o any federal law, statute, rule, regulation or interpretation of the
staff of the SEC has been proposed, adopted or enacted that, in our
judgment, might impair our ability to proceed with the exchange offer
or otherwise make it inadvisable to proceed with the exchange offer;

o an action or proceeding has been instituted or threatened in any court
or by any governmental agency that, in our judgement might impair our
ability to proceed with the exchange offer or otherwise make it
inadvisable to proceed with the exchange offer;

o there has occurred a material adverse development in any existing
action or proceeding that might impair our ability to proceed with the
exchange offer or otherwise make it inadvisable to proceed with the
exchange offer;

o any stop order is threatened or in effect with respect to the
registration statement of which this prospectus is a part or the
qualification of the indenture under the Trust Indenture Act of 1939;

o all governmental approvals that we deem necessary for the consummation
of the exchange offer have not been obtained;

o there is a change in the current interpretation by the staff of the
SEC which permits holders who have made the required representations
to us to resell, offer for resale, or otherwise transfer exchange
notes issued in the exchange offer without registration of the
exchange notes and delivery of a prospectus; or

o a material adverse change shall have occurred in our business,
condition, operations or prospects.

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

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

EXCHANGE AGENT

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

SOLICITATION OF TENDERS; EXPENSES

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

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

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

APPRAISAL RIGHTS

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

FEDERAL INCOME TAX CONSEQUENCES

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

OTHER

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

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

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

CAPITALIZATION

The following table sets forth our consolidated capitalization at September
30, 2002 and our pro forma consolidated capitalization at September 30, 2002 as
if (a) all of the original notes had been issued on September 30, 2002, and (b)
our $300 million loan to Northern Natural Gas and the subsequent repayment to us
from the proceeds of its offering of $300 million of 5.375% Senior Notes due
2012 was completed on September 30, 2002. The table should be read in
conjunction with our historical consolidated financial statements and the notes
hereto appearing elsewhere in this prospectus.

SEPTEMBER 30, 2002
-------------------
PRO FORMA
ACTUAL ADJUSTMENTS PRO FORMA
-------------- ------------------- --------------
(ALL DATA IN THOUSANDS)

Indebtedness:
Parent company short-term debt ...................... $ 167,000 $ (167,000) $ --
Subsidiary short-term debt .......................... 475,031 (450,000) 25,031
Parent company long-term debt (2) ................... 1,838,178 700,000(1) 2,538,178
Subsidiary long-term debt (3) (4) ................... 6,656,275 300,000 6,956,275
----------- ------------ -----------
Total consolidated indebtedness ..................... 9,136,484 383,000 9,519,484
Parent company-obligated mandatorily redeemable
preferred securities of subsidiary trusts held by
Berkshire Hathaway ................................. 1,727,772 1,727,772
Parent company-obligated mandatorily redeemable
preferred securities of subsidiary trusts held by
others ............................................. 335,043 335,043
Preferred securities of subsidiaries ................ 93,619 93,619
Shareholders' equity:
Zero-coupon convertible preferred stock--authorized
50,000 shares, no par value, 41,263 shares issued
and outstanding .................................... -- --
Common stock--authorized 60,000 shares, no par
value, 9,281 shares issued and outstanding ......... -- --
Additional paid-in capital .......................... 1,956,509 1,956,509
Retained earnings ................................... 510,766 510,766
Accumulated other comprehensive income .............. 24,240 24,420
----------- ------------ -----------
Total shareholders' equity .......................... 2,491,515 2,491,515
----------- ------------ -----------
Total capitalization ................................ $13,784,433 $ 383,000 $14,167,433
=========== ============ ===========

- ----------

(1) Represents the notes being registered hereby.

(2) Includes approximately $215 million current portion of parent long-term
debt.

(3) Represents debt for which the repayment obligation is at our subsidiary
level and that is non-recourse to us except as it relates to our guarantee
of approximately $47 million of the Cordova Funding Corporation Senior
Secured Bonds, our guarantee of approximately $139 million for the Salton
Sea Funding Series F Bonds, our letters of credit of approximately $49
million for our geothermal facilities located on the island of Leyte in the
Philippines, and our completion guarantee as it potentially relates to Kern
River's $875 million construction loan facility, of which approximately
$385 million was drawn as of September 30, 2002.

(4) Includes approximately $268 million current portion of subsidiary long-term
debt.

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

The following tables set forth selected historical consolidated financial
and operating data, which should be read in conjunction with our financial
statements and the related notes to those statements included in this prospectus
and with "Management's Discussion and Analysis of Financial Condition and
Results of Operations" appearing elsewhere in this prospectus. The selected
consolidated data as of and for each of the five years in the period ended
December 31, 2001 have been derived from our audited historical consolidated
financial statements. The selected consolidated data as of September 30, 2002
and for the nine months ended September 30, 2002 and 2001 have been derived from
our unaudited historical consolidated financial statements and reflect all
adjustments necessary in the opinion our management (consisting of normal
recurring accruals) for a fair presentation of such data. All data (except for
ratios) is presented in thousands.

MARCH 14,
YEAR ENDED 2000 THROUGH
DECEMBER 31, DECEMBER 31,
2001 (1) 2000 (2)
------------------ ---------------

STATEMENT OF OPERATIONS DATA:
Operating revenues ........................ $ 5,060,605 $ 4,147,867
Total revenue ............................. 5,336,804 4,242,749
Cost of sales and operating
expenses ................................. 3,881,424 3,328,790
Depreciation and amortization ............. 538,702 383,351
Interest expense, net of capitalized
interest ................................. 412,794 311,404
Provision for income taxes ................ 250,064 53,277
Minority interest ......................... 106,547 84,670
Income before extraordinary item
and cumulative effect of change
in accounting principle .................. 147,273 81,257
Extraordinary item, net of tax ............ -- --
Cumulative effect of change in
accounting principle, net of tax ......... (4,604) --
Net income (loss) ......................... 142,669 (5) 81,257
OTHER FINANCIAL DATA:
Capital expenditures ...................... $ 398,165 $ 301,948
Ratio of earnings to fixed
charges (9) .............................. 1.8 1.3
Net cash flows from operating
activities ............................... 846,998 246,407
Net cash flows from investing
activities ............................... (238,544) (2,389,160)
Net cash flows from financing
activities ............................... (258,467) 1,878,849
EBITDA (10) ............................... 1,455,380 913,959
Adjusted EBITDA (10) ...................... 1,275,887 913,959
EBIT (11) ................................. 916,678 530,608
Adjusted EBIT (11) ........................ 737,185 530,608

OUR PREDECESSOR
-------------------------------------------------------------------------
JANUARY 1,
2000 THROUGH
MARCH 13, YEAR ENDED DECEMBER 31,
2000 1999 (3) 1998 (4) 1997
----------------- ------------------ --------------- --------------------

STATEMENT OF OPERATIONS DATA:
Operating revenues ........................ $1,087,125 $ 4,184,546 $ 2,555,206 $ 2,166,338
Total revenue ............................. 1,106,609 4,466,425 2,682,711 2,270,911
Cost of sales and operating
expenses ................................. 824,742 3,201,084 1,729,944 1,453,733
Depreciation and amortization ............. 97,278 427,690 333,422 276,041
Interest expense, net of capitalized
interest ................................. 85,814 426,173 347,292 251,305
Provision for income taxes ................ 31,008 93,475 93,265 99,044
Minority interest ......................... 8,850 46,923 41,276 45,993
Income before extraordinary item
and cumulative effect of change
in accounting principle .................. 51,312 216,671 137,512 51,823
Extraordinary item, net of tax ............ -- (49,441) (7,146) (135,850)
Cumulative effect of change in
accounting principle, net of tax ......... -- -- (3,363) --
Net income (loss) ......................... 51,312 (6) 167,230 (7) 127,003 (84,027) (8)
OTHER FINANCIAL DATA:
Capital expenditures ...................... $ 44,355 $ 360,898 $ 227,071 $ 194,224
Ratio of earnings to fixed
charges (9) .............................. 1.7 1.6 1.5 1.5
Net cash flows from operating
activities ............................... 171,083 554,959 361,546 336,548
Net cash flows from investing
activities ............................... (54,874) (1,960,820) (1,007,780) (1,066,061)
Net cash flows from financing
activities ............................... (128,501) 115,875 797,338 1,741,906
EBITDA (10) ............................... 274,262 1,210,932 952,767 724,206
Adjusted EBITDA (10) ...................... 281,867 1,126,637 952,767 811,206
EBIT (11) ................................. 176,984 783,242 619,345 448,165
Adjusted EBIT (11) ........................ 184,589 698,947 619,345 535,165

NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------------------------
2002 2001
-------------------- --------------------

STATEMENT OF OPERATIONS DATA:
Operating revenues ...................................................... $ 3,404,533 $ 3,756,931
Total revenue ........................................................... 3,549,744 4,043,075
Cost of sales and operating expenses .................................... 2,232,151 2,854,940
Depreciation and amortization ........................................... 386,531 395,253
Interest expense, net of capitalized interest ........................... 438,870 290,153
Provision for income taxes .............................................. 80,226 296,088
Minority interest ....................................................... 105,166 79,952
Income before cumulative effect of change in accounting principle ....... 306,800 126,689
Cumulative effect of change in accounting principle, net of tax ......... -- (4,604)
Net income .............................................................. 306,800 (12) 122,085 (13)
OTHER FINANCIAL DATA:
Capital expenditures .................................................... $ 778,750 $ 376,962
Ratio of earnings to fixed charges (9) .................................. 1.9 2.1
Net cash flows from operating activities ................................ 682,782 790,990
Net cash flows from investing activities ................................ (2,263,656) (48,697)
Net cash flows from financing activities ................................ 1,814,900 (197,961)
EBITDA (10) ............................................................. 1,317,593 1,188,135
Adjusted EBITDA (10) .................................................... 1,263,253 967,027
EBIT (11) ............................................................... 931,062 792,882
Adjusted EBIT (11) ...................................................... 876,722 571,774

AS OF SEPTEMBER 30,
2002
--------------------

BALANCE SHEET DATA:
Property, plant, contracts and
equipment, net ........................... $ 9,168,940
Total assets .............................. 16,984,050
Short-term debt ........................... 642,031
Parent company debt ....................... 1,623,178
Subsidiary and project debt ............... 6,388,169
Current portion of long-term debt ......... 483,106
Total liabilities ......................... 12,247,784
Parent company-obligated
mandatorily redeemable preferred
securities held by Berkshire
Hathaway ................................. 1,727,772
Parent company-obligated
mandatorily redeemable preferred
securities held by others ................ 335,043
Total shareholders' equity ................ 2,491,515

OUR PREDECESSOR
-----------------------------------------
AS OF DECEMBER 31,
2001 2000 1999 1998 1997
------------- ------------- ------------- ------------- -------------

BALANCE SHEET DATA:
Property, plant, contracts and
equipment, net ........................... $ 6,527,448 $ 5,348,647 $ 5,463,329 $4,236,039 $3,528,910
Total assets .............................. 12,615,333 11,610,939 10,766,352 9,103,524 7,487,626
Short-term debt ........................... 256,012 261,656 379,523 -- --
Parent company debt ....................... 1,834,498 1,829,971 1,856,318 2,645,991 1,303,845
Subsidiary and project debt ............... 4,754,811 3,388,696 3,642,703 2,712,319 2,189,007
Current portion of long-term debt ......... 317,180 438,978 235,202 381,491 --
Total liabilities ......................... 9,767,438 8,911,349 8,978,924 7,598,040 5,282,162
Parent company-obligated
mandatorily redeemable preferred
securities held by Berkshire
Hathaway ................................. 454,772 454,772 -- -- --
Parent company-obligated
mandatorily redeemable preferred
securities held by others ................ 333,379 331,751 450,000 553,930 553,930
Total shareholders' equity ................ 1,708,167 1,576,401 994,588 827,053 765,326

- ----------

(2) Reflects our acquisition by a private investor group on March 14, 2000.

(4) Reflects the acquisition from Kiewit Diversified Group on January 2, 1998.

(5) Includes $15.2 million of non-recurring net income related to the sale of
the Northern Electric electricity and gas supply business, the sale of the
Telephone Flat Project, the sale of Western States Geothermal, the transfer
of Bali Energy Ltd. shares, and the TPL asset valuation impairment
charge.

(6) Includes $7.6 million of net non-recurring expenses for the costs related
to our acquisition by a private investor group on March 14, 2000.

(7) Includes $81.5 million of non-recurring net income related to the
settlement of political risk insurance proceeds related to our investment
in Indonesia, gains on sales of shares of McLeodUSA, our disposition of the
Coso Joint Ventures, our disposition of a 50% ownership interest of CE Gen,
CE Electric UK restructuring charges and transaction costs related to our
acquisition by a private investor group.

(8) Includes an $87 million non-recurring Indonesia asset impairment charge.

(9) For purposes of computing the ratio of earnings to fixed charges, earnings
are divided by fixed charges. Earnings represent the aggregate of (a) our
pre-tax income and (b) fixed charges, less capitalized interest. Fixed
charges represent interest (whether expensed or capitalized), amortization
of deferred financing and bank fees, and the estimated interest component
of rentals.

(10) EBITDA represents earnings before interest, taxes, depreciation, and
amortization. Adjusted EBITDA represents EBITDA adjusted for non-recurring
income and expense items as follows:

(a) items discussed in (5), which are $179.4 million before tax;

(b) item discussed in (6);

(d) item discussed in (8).

(e) items discussed in (12), which are $54.3 million before tax; and

(f) items discussed in (13), which are $221.1 million before tax.

Information concerning EBITDA and adjusted EBITDA is presented not as a
measure of operating results, but rather as a measure of our ability to
service debt. EBITDA and adjusted EBITDA should not be construed as an
alternative to either (a) operating income (determined in accordance with
GAAP) or (b) cash flow from operating activities (determined in accordance
with GAAP). Since EBITDA and adjusted EBITDA are not defined by GAAP, they
may not be calculated on the same basis as similarly titled measures of
other companies.

(11) EBIT represents earnings before interest and taxes. Adjusted EBIT
represents EBIT adjusted for non-recurring income and expense items.
Information concerning EBIT and adjusted EBIT is presented not as a measure
of operating results, but rather as a measure of our ability to service
debt. EBIT and adjusted EBIT should not be construed as an alternative to
either (a) operating income (determined in accordance with GAAP) or (b)
cash flow from operating activities (determined in accordance with GAAP).
Since EBIT and adjusted EBIT are not defined by GAAP, they may not be
calculated on the same basis as similarly titled measures of other
companies.

(12) Includes $41.3 million of non-recurring net income related to the sale of
assets by CE Gas Holdings.

(13) Includes $13.7 million of non-recurring net income related to the sale of
Western States Geothermal and the sale of Northern Supply.

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

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

As a result of the recent acquisitions of Northern Natural Gas and Kern
River, the acquisition of the electricity distribution business of Yorkshire
Electricity and the simultaneous sale of the electricity and gas supply business
of Northern Electric to the former owner of Yorkshire Electricity, which
together are referred to as the Northern Electric/Yorkshire Electricity swap,
and the acquisition by a private investor group on March 14, 2000, the Company's
future results will differ from the Company's historical results.

GENERAL

The Company is a United States-based privately owned global energy company
with publicly held fixed income securities that generates, distributes and
supplies energy to utilities, government entities, retail customers and other
customers located throughout the world. Through the Company's subsidiaries, the
Company's operations are organized and managed on seven distinct platforms:
MidAmerican Energy, Northern Natural Gas, Kern River, CE Electric UK (which
includes Northern Electric and Yorkshire Electricity), CalEnergy
Generation-Domestic, CalEnergy Generation-Foreign and HomeServices. These
platforms, with the exception of Northern Natural Gas and Kern River, are
discussed in detail in the notes to the Company's financial statements included
in this prospectus.

NORTHERN NATURAL GAS COMPANY

On August 16, 2002, the Company acquired all of the outstanding capital
stock of Northern Natural Gas from Dynegy, Inc. and its affiliates for $899
million, net of cash acquired of $1.4 million, subject to adjustment for working
capital. The Company used the proceeds from a $950 million investment in its
subsidiary trust's preferred securities by Berkshire Hathaway to finance this
acquisition.

KERN RIVER GAS TRANSMISSION COMPANY

On March 27, 2002, the Company acquired Kern River from a subsidiary of The
Williams Companies, Inc., or Williams. Kern River owns and operates a 926-mile
interstate natural gas pipeline extending from Wyoming to markets in California,
Nevada and Utah and accessing natural gas supply from large producing regions in
the Rocky Mountains and Canada. The Company paid $420 million, net of cash
acquired of $7.7 million, including transaction costs and working capital
adjustments, for Kern River. At the time of the acquisition, Kern River had $505
million of indebtedness, the unamortized portion of which remains outstanding.
The design capacity of the existing Kern River pipeline is 100% contracted
through 2011 and 84% contracted through 2016.

In connection with the Kern River acquisition, the Company issued $323
million of 11% mandatorily redeemable preferred securities of a subsidiary trust
due March 12, 2012 with scheduled principal payments beginning in 2005, and $127
million of no par, zero coupon convertible preferred stock to

Berkshire Hathaway. Each share of such preferred stock is convertible at the
option of the holder into one share of Company common stock subject to certain
adjustments as described in the Company's amended and restated articles of
incorporation.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements and related documents in conformity
with accounting principles generally accepted in the United States of America
requires management to make judgments, assumptions and estimates that affect the
amounts reported in the consolidated financial statements and accompanying
notes. Note 2 to the consolidated financial statements for the year ended
December 31, 2001 included in this prospectus describes the significant
accounting policies and methods used in the preparation of the consolidated
financial statements. Estimates are used for, but not limited to, the accounting
for revenue, the effects of certain types of regulation, impairment of
long-lived assets, and contingent liabilities. Actual results could differ from
these estimates. The following critical accounting policies are impacted
significantly by judgments, assumptions and estimates used in the preparation of
the consolidated financial statements.

REVENUE RECOGNITION

Revenues are recorded based upon services rendered and electricity, gas and
steam delivered, distributed or supplied to the end of the period. Where there
is an over recovery of United Kingdom distribution business revenues against the
maximum regulated amount, revenues are deferred in an amount equivalent to the
over recovered amount. The deferred amount is deducted from revenue and included
in other liabilities. Where there is an under recovery, no anticipation of any
potential future recovery is made.

MidAmerican Energy records unbilled revenues representing the estimated
amounts customers will be billed for services rendered between the meter reading
dates in a particular month and the end of that month. The unbilled revenues
estimate is reversed in the following month. To the extent the estimated amount
differs from that amount subsequently billed, the timing of revenues will be
affected. Accrued unbilled revenues are included in accounts receivable on the
consolidated balance sheets.

Revenues from the transportation and storage of gas are recognized based on
contractual terms and the related volumes. Northern Natural Gas and Kern River
are subject to the FERC's regulations and, accordingly, certain revenues
collected may be subject to possible refunds upon final orders in pending rate
cases. Northern Natural Gas and Kern River record rate refund liabilities
considering their regulatory proceedings and other third party regulatory
proceedings, advice of counsel and estimated total exposure, as discounted and
risk weighted, as well as collection and other risks.

SFAS NO. 71--ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION

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

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

The Company continues to evaluate the applicability of SFAS No. 71 to its
regulated energy operations and the recoverability of these assets and
liabilities through rates as there are on-going changes in the regulatory and
economic environment.

IMPAIRMENT OF LONG-LIVED ASSETS

The Company's long-lived assets consist primarily of property, plant and
equipment, goodwill and intangible assets that were acquired in business
acquisitions. The Company believes the useful lives assigned to the depreciable
assets, which generally range from 1 to 87 years, are reasonable.

Long-lived assets are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. Triggering events include a significant change in the extent or
manner in which long-lived assets are being used or in their physical condition,
in legal factors, or in the business climate that could affect the value of the
long-lived assets, including changes in regulation. The interpretation of such
events requires judgment from management as to whether such an event has
occurred and is required. If an event occurs that could affect the carrying
value of the asset and management does not identify it as triggering event,
future results of operations could be significantly affected.

Upon the occurrence of a triggering event, the carrying amount of a
long-lived asset is reviewed to assess whether the recoverable amount has
declined below its carrying amount. The recoverable amount is the estimated net
future cash flows that the Company expects to recover from the future use of the
asset, undiscounted and without interest, plus the asset's residual value on
disposal. Where the recoverable amount of the long-lived asset is less than the
carrying value, an impairment loss would be recognized to write down the asset
to its fair value which is based on discounted estimated cash flows from the
future use of the asset.

The estimate of cash flows arising from future use of the asset that are
used in the impairment analysis requires judgment regarding what the Company
would expect to recover from future use of the asset. Any changes in the
estimates of cash flows arising from future use of the asset or the residual
value of the asset on disposal based on changes in the market conditions,
changes in the use of the asset, management's plans, the determination of the
useful life of the asset and technology changes in the industry could
significantly change the calculation of the fair value or recoverable amount of
the asset and the resulting impairment loss, which could significantly affect
the results of operations.

Effective January 1, 2002, the Company adopted Statement of Financial
Accounting Standard No. 142, "Goodwill and Other Intangible Assets." SFAS No.
142 requires that amortization of goodwill and indefinite-lived intangible
assets be discontinued and that these assets be tested for impairment annually.
During the second quarter of 2002, the Company completed its initial impairment
testing of goodwill primarily using a discounted cash flow methodology. No
impairment was indicated as a result of the initial testing.

CONTINGENT LIABILITIES

The Company establishes reserves for estimated loss contingencies when it
is management's assessment that a loss is probable and the amount of the loss
can be reasonably estimated. Revisions to contingent liabilities are reflected
in income in the period in which different facts or information become known or
circumstances change that affect the previous assumptions with respect to the
likelihood or amount of loss. Reserves for contingent liabilities are based upon
management's assumptions and estimates, and advice of legal counsel or other
third parties regarding the probable outcomes of any matters. Should the
outcomes differ from the assumptions and estimates, revisions to the estimated
reserves for contingent liabilities would be required.

RESULTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2002
AND 2001

Operating revenue for the three months ended September 30, 2002, was
$1,238.5 million compared with $1,076.8 million for the same period in 2001, an
increase of 15.0%. MidAmerican Energy operating

revenue increased for the three months ended September 30, 2002, to $538.7
million from $507.7 million for the same period in 2001, primarily due to higher
volumes for regulated electricity. CE Electric UK Funding operating revenue
decreased for the three months ended September 30, 2002, to $193.4 million from
$316.3 million for the same period in 2001, primarily due to the sale of
Northern Supply in September 2001 of $209 million, partially offset by Yorkshire
Electricity distribution revenue of $103 million. The remaining change in
operating revenue primarily relates to (1) the increase of revenue at
HomeServices of $147.6 million primarily due to acquisitions in 2002 and late
2001, (2) the acquisition of Kern River in March 2002, which accounted for $39.9
million of operating revenue and (3) the acquisition of Northern Natural Gas in
August 2002, which accounted for $39.1 million of operating revenue.

Operating revenue for the nine months ended September 30, 2002, was
$3,404.5 million compared with $3,756.9 million for the same period in 2001, a
decrease of 9.4%. MidAmerican Energy operating revenue decreased for the nine
months ended September 30, 2002, to $1,582.6 million from $1,897.8 million for
the same period in 2001, primarily due to lower volumes and rates for regulated
and non-regulated gas. CE Electric UK Funding operating revenues decreased for
the nine months ended September 30, 2002, to $597.0 million from $1,222.3
million for the same period in 2001, primarily due to the sale of Northern
Supply in September 2001 of $889 million, partially offset by Yorkshire
Electricity distribution revenue of $276 million. The remaining change in
operating revenue primarily relates to (1) the increase of revenue at
HomeServices of $382.5 million primarily due to acquisitions in 2002 and late
2001, (2) the acquisition of Kern River in March 2002, which accounted for $87.0
million of operating revenue and (3) the acquisition of Northern Natural Gas in
August 2002, which accounted for $39.1 million of operating revenue.

The following data represents sales from MidAmerican Energy:

THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
------------------- -------------------
2002 2001 2002 2001
---- ---- ---- ----

Electricity Retail Sales (GWh) ............. 4,987 4,679 13,254 12,502
Electricity Sales for Resale (GWh) ......... 2,506 1,772 7,485 6,341
Regulated and Non-Regulated Gas
Supplied (Thousands of MMBtus) ........... 38,936 53,605 169,200 198,789

MidAmerican Energy's electric retail sales and electric sales for resale
increased for three months ended September 30, 2002, from the same period in
2001 due to higher temperatures in the third quarter of 2002. Retail gas
supplied decreased due to decreased non-regulated activity for the three months
ended September 30, 2002, compared to the same period in 2001.

MidAmerican Energy electric retail sales increased for the nine months
ended September 30, 2002 from the same period in 2001 due primarily to higher
temperatures in 2002, primarily in the third quarter of 2002. Electric sales
for resale increased for the nine months ended September 30, 2002 from the same
period in 2001 due to availability of Cordova Energy Company LLC, or Cordova
Energy, an indirect wholly owned subsidiary of the Company, and lower retail
usage in the first quarter of 2002, allowing for more energy to be sold in the
wholesale markets. Regulated and non-regulated gas supplied decreased due to
colder temperatures during the first quarter of 2001 and decreased
non-regulated activity.

CE Electric UK Funding distributed 9,473 GWh of electricity in the three
months ended September 30, 2002, compared with 4,457 GWh of electricity in the
same period in 2001. CE Electric UK Funding distributed 30,252 GWh of
electricity in the nine months ended September 30, 2002, compared with 13,016
GWh of electricity in the same period in 2001. The increase in electricity
distributed for both periods ended September 30, 2002, is primarily due to the
acquisition of Yorkshire Electricity distribution.

Kern River transported 90,532,000 MMBtus in the three months ended
September 30, 2002, and 190,195,000 MMBtus since the Company acquired Kern River
on March 27, 2002.

Northern Natural Gas transported 121,028,500 MMBtus since the Company
acquired Northern Natural Gas on August 16, 2002.

Income on equity investments for the three months ended September 30, 2002,
was $10.9 million compared with $6.3 million for the same period in 2001. The
increase was primarily due to higher earnings at CE Gen as a result of higher
energy prices in 2002 and the allowance for doubtful accounts accrual in 2001,
and income from a HomeServices' joint venture which was fully consolidated in
2001, partially offset by lower equity earnings due to impairment of alternative
energy project funds in 2002.

Income on equity investments for the nine months ended September 30, 2002,
was $29.9 million compared with $23.6 million for the same period in 2001. The
increase was primarily due to income from a HomeServices' joint venture that was
fully consolidated in 2001.

Interest and other income for the three months ended September 30, 2002,
was $32.7 million compared with $223.9 million for the same period in 2001. The
decrease was primarily due to the $200.3 million gain on the sale of Northern
Supply in September 2001.

Interest and other income for the nine months ended September 30, 2002, was
$115.3 million compared with $262.5 million for the same period in 2001. The
decrease was primarily due to the gain on sale of Northern Supply in September
2001, partially offset by the $54.3 million gain on the sale of various CE Gas
Holdings assets in May 2002.

Cost of sales for the three months ended September 30, 2002, was $443.1
million compared with $473.0 million for the same period in 2001, a decrease of
6.3%. Cost of sales for the nine months ended September 30, 2002, was $1,283.2
million compared with $2,010.2 million for the same period in 2001, a decrease
of 36.2%. The decreases for both periods relates primarily to the sale of
Northern Supply and decreased gas revenue at MidAmerican Energy, partially
offset by increase cost of sales at HomeServices due to higher commission on the
higher revenues as a result of acquisitions.

Operating expenses for the three months ended September 30, 2002, were
$343.3 million compared with $293.9 million for the same period in 2001. The
increase was primarily due to higher costs at HomeServices of $32.3 million as a
result of acquisitions and operating expenses due to the acquisition of Northern
Natural Gas of $26.6 million, partially offset by lower costs at MidAmerican
Energy of $23.4 million due to the restructuring of the Cooper Nuclear Station
contract with the Nebraska Public Power District, or NPPD, and lower energy
efficiency expenses.

Operating expenses for the nine months ended September 30, 2002, were
$948.9 million compared with $844.8 million for the same period in 2001. The
increase was primarily due to higher costs at HomeServices of $77.5 million as a
result of acquisitions and operating expenses due to the acquisitions of
Northern Natural Gas of $26.6 million and Kern River of $18.2 million, partially
offset by lower costs at MidAmerican Energy of $22.0 million due to the
restructuring of the Cooper Nuclear Station contract and lower energy efficiency
expenses.

Depreciation and amortization for the three months ended September 30,
2002, was $129.4 million compared with $122.7 million for the same period in
2001. The increase was primarily due to higher depreciation at MidAmerican
Energy of $12.5 million primarily due to higher Iowa revenue sharing accruals,
the commencement of commercial operation at CE Casecnan of $5.8 million, and
depreciation expense due to the acquisitions of Northern Natural Gas of $5.8
million and Kern River of $4.9 million, partially offset by the discontinuance
of amortizing goodwill beginning January 1, 2002 of $24.8 million.

Depreciation and amortization for the nine months ended September 30, 2002,
was $386.5 million compared with $395.3 million for the same period in 2001. The
decrease was primarily due to discontinuance of amortizing goodwill beginning
January 1, 2002 of $74.7 million, partially offset by the commencement of
commercial operations at CE Casecnan of $17.6 million, higher depreciation at
MidAmerican Energy of $17.3 million primarily due to higher Iowa revenue sharing
accruals, depreciation expense due to the acquisitions of Kern River of $12.2
million and Northern Natural Gas of $5.8 million and increased amortization at
HomeServices of $8.9 million due to intangible assets amortization related to
acquisitions.

Interest expense, less amounts capitalized, for the three months ended
September 30, 2002, was $159.3 million compared with $99.9 million for the same
period in 2001, an increase of 59.5%. The increase was due primarily to the
increase of interest expense at CE Electric UK Funding of $24.4 million
predominantly due to the debt related to the Yorkshire Electricity acquisition,
the discontinuance of capitalizing interest related to the Casecnan Project of
$13.0 million, and interest expense due to the acquisitions of Kern River and
Northern Natural Gas of $12.9 million and $8.1 million, respectively.

Interest expense, less amounts capitalized, for the nine months ended
September 30, 2002, was $438.9 million compared with $290.2 million for the same
period in 2001, an increase of 51.2%. The increase was primarily due to the
increase of interest expense at CE Electric UK Funding of $68.4 million
predominantly due to the debt related to the Yorkshire Electricity acquisition,
the discontinuance of capitalizing interest related to the Casecnan Project and
the Cordova Project of $37.7 million and $9.7 million, respectively, and
interest expense due to debt related to the acquisitions of Kern River and
Northern Natural Gas of $22.4 million and $8.1 million, respectively.

Tax expense for the three months ended September 30, 2002, was $26.8
million compared with $241.9 million for the same period in 2001. The decrease
is due primarily to the tax expense of $199.9 million related to the sale of the
Northern Supply business in September 2001 and the recognition of a tax benefit
of $21.1 million in connection with the sale of the CE Gas Holdings assets in
May 2002.

Tax expense for the nine months ended September 30, 2002, was $80.2 million
compared to $296.1 million for the same period in 2001. The decrease is due
primarily to the tax expense related to the sale of the Northern Supply business
in September 2001, the release of the tax obligation of $35.7 million in
connection with the execution of the TPL restructuring agreement in the U.K.,
and the recognition of a tax benefit in connection with the sale of the CE Gas
Holdings assets in 2002.

Minority interest for the three months ended September 30, 2002, was $45.3
million compared with $27.8 million for the same period in 2001. Minority
interest for the nine months ended September 30, 2002, was $105.2 million
compared with $80.0 million for the same periods in 2001. Minority interest
includes the dividends on the Company-obligated mandatorily redeemable preferred
securities of subsidiary trusts. The increases in minority interest for both
periods is primarily due to the issuance of Company-obligated mandatorily
redeemable preferred securities of subsidiary trusts relating to the Kern River
and Northern Natural Gas acquisitions.

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

RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2001 AND THE PERIODS
MARCH 14, 2000 THROUGH DECEMBER 31, 2000, AND JANUARY 1, 2000 THROUGH MARCH 13,
2000

The following is a discussion of the historical results of the Company for
the year ended December 31, 2001 and the period March 14, 2000 through December
31, 2000, and of the Company's predecessor, MEHC (Predecessor), for the period
January 1, 2000 through March 13, 2000. Results for the Company include the
impact of the Company's acquisition by a private investor group beginning March
14, 2000 which are predominately the minority interest costs on issuance of
Company-obligated mandatorily redeemable preferred securities of a subsidiary
trust and the effects of purchase accounting, including goodwill amortization
and fair value adjustments to the carrying value of assets and liabilities. In
order to provide comparability between periods, the Company has prepared pro
forma results as if the Company's acquisition by a private investor group had
occurred at the beginning of each year after giving effect to pro forma
adjustments related to the acquisition, including the issuance of the 11% trust
preferred securities. The discussion therefore will highlight any significant
variances on a pro forma basis from the year ended December 31, 2000 to the year
ended December 31, 2001.

Pro forma operating revenue for the year ended December 31, 2001 was
$5,060.6 million compared with $5,235.0 million for the same period in 2000, a
decrease of 3.3%. MidAmerican Energy operating revenue increased for the year
ended December 31, 2001 to $2,752.5 million from $2,576.9 million for the same
period in 2000, primarily due to increases in volumes of non-regulated gas sold
and increases in volumes and prices on off-system electricity sales. CE Electric
UK operating revenue decreased for the year ended December 31, 2001 to $1,444.0
million from $1,997.9 million for the same period in 2000, primarily due to the
Northern Electric/Yorkshire Electricity swap and changes in foreign exchange
rates. The supply business that was sold is generally a high volume business
that tends to operate at lower profitability levels than the distribution
business. The remaining increase primarily relates to the increase of revenue at
HomeServices due to acquisitions and the inclusion of a joint venture which was
previously accounted for as an equity investment and the commencement of
operations of the Cordova project in June 2001.

The following data represents sales from MidAmerican Energy:

YEAR ENDED DECEMBER
31,
---------------------
2001 2000
--------- ---------

Electricity Retail Sales (GWh) ............ 17,207 16,715
Electricity Wholesale Sales (GWh) ......... 7,755 6,941
Regulated and Non-Regulated Gas Supplied
(Thousands of MMBtus) .................... 264,338 174,385

MidAmerican Energy electric retail sales increased for the year ended
December 31, 2001 from the same period in 2000 due to the more extreme
temperatures substantially offset by a decrease in non-weather related sales.
Electric wholesale sales increased for the year ended December 31, 2001 from the
same period in 2000 due to higher production at the Cooper and Neal power plants
and favorable market conditions. Regulated and non-regulated gas supplied
increased due principally to growth in the non-regulated markets for the year
ended December 31, 2001 compared to the same period in 2000.

The following data represents the supply and distribution operations in the
United Kingdom:

YEAR ENDED DECEMBER
31,
------------------
2001 2000
-------- -------

Electricity Supplied (GWh) ................. 12,745 19,925
Gas Supplied (Thousands of MMBtus) ......... 40,738 51,035
Electricity Distributed (GWh) .............. 23,770 16,350

The decrease in electricity and gas supplied for the year ended December
31, 2001 is due to the sale of Northern Electric's electricity and gas supply
business in September 2001. The increase in electricity distributed for the year
ended December 31, 2001 was due to the addition of Yorkshire Electricity and
changes in demand in the distribution area.

Pro forma interest and other income for the year ended December 31, 2001
was $96.7 million compared with $114.4 million for the same period in 2000. The
decrease was due primarily to reduced interest income and lower income from
equity investments.

The non-recurring gains in 2001 are comprised mainly of the pre-tax gain on
the sale of Northern Electric's electricity and gas supply business of $196.7
million, the loss on the impairment of TPL of $58.8 million, the gain on the
sale of Telephone Flat, a geothermal development project, of $20.7 million, the
gain on the transfer of shares of Bali, an indirect wholly owned subsidiary of
the Company, of $10.4 million, and the gain on the sale of Western States
Geothermal Company, an indirect wholly owned subsidiary of the Company, of $9.8
million. The after-tax gains and (losses) for the sale of Northern Electric's
electricity and gas supply business, the TPL impairment, the Telephone Flat
sale, the transfer of the Bali shares, and the Western States Geothermal sale
were $10.8 million, ($20.7) million, $12.2 million, $6.5 million and $6.4
million, respectively.

Pro forma cost of sales for the year ended December 31, 2001 was $2,705.0
million compared with $3,029.7 million for the same period in 2000, a decrease
of 10.7%. The decrease relates primarily to decreased cost of sales at CE
Electric UK due to the sale of Northern Electric's electricity and gas supply
business, lower foreign exchange rates and lower electricity volumes and prices,
partially offset by increased volumes and prices for both regulated and
non-regulated gas at MidAmerican Energy, and acquisitions at HomeServices.

Pro forma operating expenses for the year ended December 31, 2001 were
$1,176.4 million compared with $1,123.6 million for the same period in 2000. The
increase was primarily due to higher costs at HomeServices due to acquisitions
and the inclusion of a joint venture which was previously accounted for as an
equity investment and higher costs at MidAmerican Energy due to costs related to
Cooper Nuclear Station, accounts receivable discounts and bad debts, partially
offset by lower costs at CE Electric UK due to the sale of Northern Electric's
electricity and gas supply business, lower pension costs and a lower exchange
rate, partially offset by the addition of Yorkshire Electricity.

Pro forma depreciation and amortization for the year ended December 31,
2001 was $538.7 million compared with $479.6 million for the same period in
2000. This increase was due to higher depreciation at MidAmerican Energy due to
inclusion of an Iowa revenue sharing accrual and an increase in depreciation
rates implemented in 2001 and amortization of intangible assets related to the
HomeServices acquisitions, partially offset by lower depreciation at CE Electric
UK due to lower amortization of operational assets and a lower exchange rate,
partially offset by the addition of Yorkshire Electricity.

Pro forma interest expense, less amounts capitalized, for the year ended
December 31, 2001 was $412.8 million compared with $398.1 million for the same
period in 2000, an increase of 3.7%. This increase is due to increased interest
expense associated with the debt acquired with Yorkshire Electricity and lower
capitalized interest on the mineral extraction process, partially offset by
lower average outstanding debt balances and lower foreign exchange rates at
Northern Electric.

The loss on non-recurring items of $7.6 million in the period from January
1, 2000 through March 13, 2000 represents the costs incurred related to the
Company's acquisition by a private investor group.

Pro forma tax expense for the year ended December 31, 2001 was $250.1
million compared with $81.6 million for the same period in 2000. The increase is
due primarily to the tax on the gain related to the sale of Northern Electric's
electricity and gas supply business and higher pre-tax income.

Pro forma minority interest for the year ended December 31, 2001 was $106.5
million compared with $104.3 million for the same period in 2000. The increase
is primarily due to increased minority interest at HomeServices.

The cumulative effect of change in accounting principle of $4.6 million in
2001 represents the change in accounting for major maintenance and overhauls.

Pro forma net income for the year ended December 31, 2001 was $142.7
million compared with $124.9 million for the same period in 2000.

RESULTS OF OPERATIONS FOR THE PERIODS MARCH 14, 2000 THROUGH DECEMBER 31, 2000,
JANUARY 1, 2000 THROUGH MARCH 13, 2000 AND FOR THE YEAR ENDED DECEMBER 31, 1999

The following is a discussion of the historical results of the Company for
the period March 14, 2000 through December 31, 2000, and of MEHC (Predecessor)
for the period January 1, 2000 through March 13, 2000, and for the year ended
December 31, 1999. Results for the Company include the results of MEHC
(Predecessor) beginning March 14, 2000, in conjunction with the Company's
acquisition by a private investor group. The impact of the transaction is
reflected in the Company's results of operations, predominately minority
interest costs on issuance of Company-obligated mandatorily redeemable preferred
securities of a subsidiary trust and the effects of purchase accounting,
including goodwill amortization and fair value adjustments to the carrying value
of assets and liabilities. In order to provide comparability between periods,
the Company has prepared pro forma results as if the Company's acquisition by a
private investor group and the MidAmerican Energy acquisition had occurred at
the

beginning of each year after giving effect to pro forma adjustments related to
the acquisitions, including the sales of the qualified facilities, the
redemption of limited recourse notes, the redemption of the senior discount
notes and the issuance of the 11% trust preferred securities. The discussion
therefore will highlight any significant variances on a pro forma basis from the
year ended December 31, 1999 to the year ended December 31, 2000.

Pro forma operating revenue for the year ended December 31, 2000 was
$5,235.0 million compared with $4,572.8 million for the same period in 1999, an
increase of 14.5%. MidAmerican Energy operating revenue increased for the year
ended December 31, 2000 to $2,576.9 million from $1,871.9 million for the same
period in 1999, primarily due to increases in non-regulated gas sales and higher
prices in regulated gas. CE Electric UK operating revenue decreased for the year
ended December 31, 2000 to $1,997.9 million from $2,072.2 million for the same
period in 1999, primarily due to lower volumes of electricity supplied in the
franchise area and lower foreign exchange rates partially offset by higher
volumes of electricity supplied out of the franchise area and distribution
revenue from access charges. The remaining increase primarily related to the
increase of revenue at HomeServices due to acquisitions in late 1999.

The following data represents sales from MidAmerican Energy:

YEAR ENDED DECEMBER
31,
---------------------
2000 1999
--------- ---------

Electricity Retail Sales (GWh) ............ 16,715 16,007
Electricity Wholesale Sales (GWh) ......... 6,941 7,168
Regulated and Non-Regulated Gas Supplied
(Thousands of MMBtus) .................... 174,385 138,387

MidAmerican Energy electricity retail sales increased for the year ended
December 31, 2000 from the same period in 1999 due to increased customers and
non-weather related sales partially offset by more moderate temperatures.
Electricity wholesale sales decreased for the year ended December 31, 2000 from
the same period in 1999 due to a lower power plant output primarily from the
Cooper Nuclear Station which results in lower energy available for resale. Gas
supplied increased due to an increase in customers, an increase in heating
degree days and an increase in trading activity of non-regulated sales.

The following data represents the supply and distribution operations in the
United Kingdom:

YEAR ENDED DECEMBER
31,
------------------
2000 1999
-------- -------

Electricity Supplied (GWh) ................. 19,925 17,984
Electricity Distributed (GWh) .............. 16,350 15,943
Gas Supplied (Thousands of MMBtus) ......... 51,035 48,435

The increase in electricity supplied for the year ended December 31, 2000
was due primarily to the increase in volumes for customers outside of the
franchise area. The increase in electricity distributed for the year ended
December 31, 2000 was due to changes in demand in the franchise area. The
increase in gas supplied in 2000 from 1999 reflected higher volume in the
industrial and commercial markets.

Pro forma interest and other income for the year ended December 31, 2000
was $114.4 million compared with $145.4 million for the same period in 1999. The
decrease was due primarily to the reduced interest income resulting from lower
cash balances, lower dividends from TPL and gains on other asset sales in 1999,
partially offset by proceeds of Company-owned life insurance of $7.5 million
received in 2000.

The 1999 gain on non-recurring items resulted from the sale of
approximately 6.74 million shares of McLeodUSA Class A common stock, through a
secondary offering by McLeodUSA, at $55.625 per share. Proceeds from the sale
exceeded $375 million, with a resulting after-tax gain to the Company of
approximately $47.1 million.

As a result of the sales of the Coso Joint Ventures geothermal projects
previously owned by the Company, and an interest in CE Gen, the Company recorded
a gain of $20.2 million in the first quarter of 1999.

In the fourth quarter of 1999, the Company recorded a pre-tax gain of $40.3
million relating to insurance proceeds received from an arbitration settlement
between Himpurna California Energy Ltd. and Patuha Power Ltd., former
subsidiaries of the Company, and P.T. PLN (Persero), an Indonesian national
electric utility.

Pro forma cost of sales for the year ended December 31, 2000 was $3,029.7
million compared with $2,398.6 million for the same period in 1999, an increase
of 26.3%. The increase related to increased sales at MidAmerican Energy and
HomeServices.

Pro forma operating expense for the year ended December 31, 2000 was
$1,123.6 million compared with $1,115.8 million for the same period in 1999. The
increase primarily relates to the increase of operating expenses at HomeServices
due to acquisitions in late 1999.

Pro forma depreciation and amortization for the year ended December 31,
2000 was $479.6 million compared with $462.0 million for the same period in
1999. The increase was primarily due to higher depreciation at CE Electric UK
primarily due to higher production at CE Gas Holdings, the Company's United
Kingdom gas exploration subsidiary.

Pro forma interest expense, less amounts capitalized, for the year ended
December 31, 2000 was $398.1 million compared with $447.0 million for the same
period in 1999, a decrease of 10.9%. This decrease was due to the repayment of
the 9.5% Senior Notes in 1999 and other reduced indebtedness and an increase in
capitalized interest related to the construction of the Casecnan, Cordova and
Zinc projects.

The loss on non-recurring items of $7.6 million in the period from January
1, 2000 through March 13, 2000 represents the costs related to the Company's
acquisition by a private investor group.

Pro forma tax expense for the year ended December 31, 2000 was $81.6
million compared with $89.4 million for the same period in 1999. The decrease
was due primarily to lower pretax income in 2000.

Pro forma minority interest for the year ended December 31, 2000 was $104.3
million compared with $101.9 million for the same period in 1999. Minority
interest included the dividends on the $455 million of Company-obligated
mandatorily redeemable preferred securities of subsidiary trusts.

Pro forma net income for the year ended December 31, 2000 was $124.9
million compared with $138.3 million for the same period in 1999.

LIQUIDITY AND CAPITAL RESOURCES

The Company has available a variety of sources of liquidity and capital
resources, both internal and external. These resources provide funds required
for current operations, construction expenditures, debt retirement and other
capital requirements. The Company may from time to time seek to retire its
outstanding debt through cash purchases in the open market, privately negotiated
transactions or otherwise. Such repurchases or exchanges, if any, will depend on
prevailing market conditions, the Company's liquidity requirements, contractual
restrictions and other factors. The amounts involved may be material.

The Company's cash and cash equivalents were $662 million at September 30,
2002, compared to $387 million at December 31, 2001. Each of the Company's
direct or indirect subsidiaries is organized as a legal entity separate and
apart from the Company and its other subsidiaries. Pursuant to separate
financing agreements at each subsidiary, the assets of each subsidiary may be
pledged or encumbered to support or otherwise provide the security for their own
project or subsidiary debt. It should not be assumed that any asset of any
subsidiary of the Company will be available to satisfy the obligations of the
Company or any of its other subsidiaries; provided, however, that unrestricted
cash or other assets which are available for distribution may, subject to
applicable law and the terms of financing arrangements for such parties, be
advanced, loaned, paid as dividends or otherwise distributed or contributed to
the Company or affiliates thereof.

The Company generated cash flows from operations of $683 million for the
nine months ended September 30, 2002, compared with $791 million for the same
period in 2001. The decrease was primarily due to timing of changes in working
capital activities, partially offset by positive impacts of the Kern River and
real estate companies acquisitions.

The remaining increase to cash and cash equivalents is primarily due to the
issuances of convertible preferred stock, trust preferred securities and
subsidiary and project debt and cash proceeds from sale of assets, partially
offset by the Kern River and Northern Natural Gas acquisitions, purchase of
convertible preferred securities, repayment of subsidiary and project debt and
capital expenditures for operating and construction projects.

In addition, the Company recorded separately restricted cash and
investments of $63.9 million and $54.8 million at September 30, 2002, and
December 31, 2001, respectively. The restricted cash balance as of September 30,
2002, is comprised primarily of amounts deposited in restricted accounts which
is reserved for the service of debt obligations.

OTHER INVESTMENTS

On March 27, 2002, a newly formed subsidiary of the Company invested $275
million in Williams in exchange for shares of 9 7/8% cumulative convertible
preferred stock of Williams. In connection with this investment, the Company
issued $275 million of no par, zero coupon convertible preferred stock to
Berkshire Hathaway. Dividends on the Williams' preferred stock are scheduled to
be received quarterly, and commenced on July 1, 2002. This investment is
accounted for under the cost method. The Company is aware that there have been
public announcements that Williams' financial condition has deteriorated as a
result of, among other factors, reduced liquidity. The Company had not recorded
an impairment on this investment as of September 30, 2002, and is monitoring the
situation.

DEBT ISSUANCES AND REDEMPTIONS

On February 8, 2002, MidAmerican Energy issued $400 million of 6.75%
medium-term notes due in 2031. The proceeds were used to refinance existing debt
and preferred securities and for other corporate purposes. On March 11, 2002,
MidAmerican Energy redeemed all $100 million of its 7.98% MidAmerican
Energy-obligated preferred securities of a subsidiary trust at 100% of the
principal amount plus accrued interest.

On May 1, 2002, MidAmerican Energy reacquired all $26.7 million of its
$7.80 series of preferred securities. Of this amount, $13.3 million of preferred
securities were redeemed at 100% of the principal amount plus accrued dividends,
and the remaining $13.4 million was redeemed at 103.9% of the principal amount
plus accrued dividends.

On June 21, 2002, Kern River closed on a bank loan facility providing for
aggregate loans of up to $875 million to be used for the construction of the
Kern River 2003 Expansion Project. The facility, which matures 15 years after
the 2003 Expansion Project commences operation, has a variable interest rate
which increases over the term of the facility from 1.375% to 4.5% over LIBOR.
Kern River had drawn $385 million on this facility as of September 30, 2002. In
connection with this facility, the Company guaranteed the completion of the 2003
Expansion Project as described below in "Kern River's 2003 Expansion Project
Financing."

On March 1, 2001, MidAmerican Funding, LLC retired $200 million of 5.85%
senior secured notes due 2001. On March 19, 2001, MidAmerican Funding, LLC
issued $200 million of 6.75% senior secured notes due March 1, 2011.

YORKSHIRE ELECTRICITY

In August 2002, CE Electric UK Funding acquired the remaining 5.25% of
Yorkshire Electricity that it did not already own from Xcel Energy
International, an affiliate of Xcel Energy Inc., for $33.3 million.

REAL ESTATE COMPANIES 2002 ACQUISITIONS

In 2002, HomeServices separately acquired three real estate companies for
an aggregate purchase price of approximately $100.0 million, net of cash
acquired, plus working capital and certain other adjustments. For the year ended
December 31, 2001, these real estate companies had combined revenue of
approximately $356.0 million on 42,000 closed sides representing $13.7 billion
of sales volume. Additionally, HomeServices is obligated to pay a maximum
earnout of $18.5 million calculated based on 2002 financial performance
measures. These purchases were financed using HomeServices' $65.0 million
revolving credit facility and the Company's corporate revolver for $40.0
million, which was contributed to HomeServices as equity. The Company is in the
process of completing the allocation of the purchase prices to the assets and
liabilities acquired.

CALENERGY GAS HOLDING DISPOSAL

In May 2002, CE Gas Holdings, an indirect wholly owned subsidiary of the
Company, completed the sale of several of its U.K. natural gas assets to Gaz de
France for (pounds sterling)137.0 million (approximately $200.0 million). CE Gas
Holdings sold four natural gas-producing fields located in the southern basin of
the U.K. North Sea including Anglia, Johnston, Schooner and Windermere. The
transaction also included the sale of rights in four gas fields in development
and construction and three exploration blocks owned by CE Gas Holdings.

ACCOUNTS RECEIVABLE SOLD

In 1997, MidAmerican Energy entered into a revolving agreement, which
expired on October 29, 2002, to sell all of its right, title and interest in the
majority of its billed accounts receivable to MidAmerican Energy Funding
Corporation, a special purpose entity established to purchase accounts
receivable from MidAmerican Energy. MidAmerican Energy Funding Corporation in
turn sold receivable interests to outside investors. In consideration for the
sale, MidAmerican Energy received cash and a subordinated note, bearing interest
at 8%, from MidAmerican Energy Funding Corporation. As of September 30, 2002,
the revolving cash balance was $36.0 million and the amount outstanding under
the subordinated note was $89.2 million. The agreement was structured as a true
sale, under which the creditors of MidAmerican Energy Funding Corporation were
entitled to be satisfied out of the assets of MidAmerican Energy Funding
Corporation prior to any value being returned to MidAmerican Energy or its
creditors. Therefore, the accounts receivable sold are not reflected on the
Company's consolidated balance sheets. As of September 30, 2002, $126.0 million
of accounts receivable, net of reserves, were sold under the agreement.
MidAmerican Energy did not extend or replace this agreement.

CONSTRUCTION

MIDAMERICAN ENERGY

MidAmerican Energy's primary need for capital is for utility construction
expenditures. For the first nine months of 2002, utility construction
expenditures totaled $228.8 million, including allowance for funds used during
construction, or capitalized financing costs, and Quad Cities Station nuclear
fuel purchases. All such expenditures were met with cash generated from utility
operations.

Forecasted MidAmerican Energy utility construction expenditures, including
allowances for funds used during construction are $382.0 million for 2002 and
$1.614 billion for 2003 through 2006. Capital expenditure needs are reviewed
regularly by management and may change significantly as a result of such
reviews.

MidAmerican Energy has announced plans to construct an electric generating
plant, the Greater Des Moines Energy Center, in Iowa. The plant will provide
service to regulated retail electricity customers and be included in MidAmerican
Energy's regulated rate base in Iowa, Illinois and South Dakota. Wholesale sales
may also be made from the plant to the extent the power is not needed for
regulated retail service. The plant will be a 540 MW (500 MW based on expected
accreditation) natural gas-fired plant with an estimated cost of $415.0 million.
MidAmerican Energy will own 100% of the plant and will operate it. The

plant will be operated in simple cycle mode during 2003 and 2004, with combined
cycle operation commencing in 2005. MidAmerican Energy commenced construction of
the plant in 2002 following receipt of two orders from the IUB. The first order
authorized construction of the plant. The second order, issued May 29, 2002,
specified the principles that will apply to the plant over its life for purposes
of Iowa ratemaking and was sought by MidAmerican Energy to limit regulatory
risk.

MidAmerican Energy presently expects that all utility construction
expenditures through 2007 will be met with the issuance of long-term debt and
cash generated from utility operations, net of dividends. The actual level of
cash generated from utility operations is affected by, among other things,
economic conditions in the utility service territory, weather and federal and
state legislation and regulatory actions.

KERN RIVER'S 2003 EXPANSION PROJECT FINANCING

On July 17, 2002, Kern River received approval from the FERC to construct,
own and operate the 2003 Expansion Project. The 2003 Expansion Project will loop
most of Kern River's existing mainline, construct three new compressor stations
and upgrade or modify Kern River's six existing compressor stations. The 2003
Expansion Project, which is expected to be completed and operational by May
2003, will increase Kern River's capacity by approximately 900mmcf/day. Service
will be provided under long-term contracts subject to incremental rates. The
estimated cost of the expansion is approximately $1.2 billion, which will be
financed with 70% debt and 30% equity, consistent with Kern River's existing
capital structure, the application for the FERC approval described above and the
limitations contained in the indenture for Kern River's existing secured senior
notes.

Construction will initially be funded with the proceeds of an $875.0
million credit facility entered into by Kern River on June 21, 2002, until 70%
of the projected capitalized costs of the 2003 Expansion Project has been spent.
The final 30% of the capitalized costs of the 2003 Expansion Project will be
funded with equity from the Company. The credit facility is structured as a
two-year construction facility followed by a term loan with a final maturity 15
years after completion of the 2003 Expansion Project. However, Kern River
presently intends to refinance the credit facility through a bond offering or
other capital markets transaction following completion of the 2003 Expansion
Project. Prior to completion of the 2003 Expansion Project, the credit facility
lenders will have limited recourse to Kern River and its assets and cash flow,
and will have recourse to the Company's completion guarantee described below.
Following completion of the 2003 Expansion Project, until such time as the Kern
River credit facility is refinanced, the lenders under the credit facility will
share equally and ratably with the existing Kern River senior secured
noteholders in all of the collateral pledged to such senior secured noteholders.

Pursuant to the Company's completion guarantee, it has guaranteed that
"completion" of the 2003 Expansion Project will occur on or prior to the
earliest of any abandonment by Kern River of the project, the occurrence of
certain other acceleration events and June 30, 2004. The potential acceleration
events include any downgrading of the Company's public debt rating to below
investment grade by either S&P or Moody's unless a satisfactory substitute
guarantor assumes the Company's obligations under the completion guarantee
within 60 days after any such downgrade; Berkshire Hathaway ceasing to own at
least a majority of the outstanding capital stock of the Company; and certain
other customary events of default by the Company. In the completion guarantee,
the Company has also agreed to cause capital contributions to be made to Kern
River in a minimum aggregate amount of at least $375 million by June 30, 2004 or
upon any earlier event of abandonment of the project. For purposes of the
Company's completion guarantee, the term "completion" is defined in the Kern
River credit agreement to mean satisfaction of a number of conditions, the most
significant of which include the requirements that the 2003 Expansion Project be
substantially complete and operable and able to permit Kern River to perform its
obligations under all of the long-term firm gas transportation service
agreements entered into in connection with the 2003 Expansion Project; that the
shippers under such agreements shall have begun to incur the obligation to pay
reservation fees thereunder; and that the FERC shall have authorized Kern River
to begin collecting rates under its tariff and its shipper agreements; provided
that the 2003 Expansion Project shall still be deemed to have been completed if
it is less than substantially complete but it demonstrates at least 80% design
capacity and Kern River's debt service coverage ratios as defined in its senior
secured note indenture are not less than 1:55 to 1:0. There are a number of
other conditions to

completion, including requirements that all conditions to completion of the
expansion contained in Kern River's senior secured note indenture be satisfied
and all of Kern River's obligations under its credit agreement then share pari
passu in all collateral available to Kern River's senior secured noteholders.
The Company's completion guarantee shall terminate upon the earlier of
completion of the 2003 Expansion Project or repayment in full of all obligations
under the Kern River credit facility.

ZINC RECOVERY PROJECT

CalEnergy Minerals LLC, our indirect wholly owned subsidiary, is
constructing the Zinc Recovery Project. The Zinc Recovery Project is designed to
have a capacity of approximately 30,000 metric tons per year, and commenced
initial commercial operations in 2002. We expect the Zinc Recovery Project to be
at 100% production in mid-2003. Total project costs of the Zinc Recovery Project
are expected to be approximately $244.0 million, net of settlement proceeds from
a dispute with the contractor, which is being funded by $140.5 million of debt
and the balance from funds provided by the Company. The Zinc Recovery Project
has incurred $213.9 million, net of settlement proceeds from a dispute with the
contractor, of such costs through September 30, 2002.

DEVELOPMENT ACTIVITY

MidAmerican Energy has announced plans to develop a 750 MW super-
critical-temperature, coal-fired plant fueled with Powder River low-sulfur coal
in Pottawattamie County, Iowa. If constructed, MidAmerican Energy will operate
the plant and expects to own 450 MW of the plant. Municipal, cooperative and
public power utilities will own the remainder, which is a typical ownership
arrangement for large baseload plants in Iowa. MidAmerican Energy's investment
in the plant is projected to be approximately $785.0 million, including the cost
of related transmission facilities, taxes and allowance for funds used during
construction. The plant will provide service to regulated customers and be
included in MidAmerican Energy's regulated rate base in Iowa, Illinois and South
Dakota. Wholesale sales may also be made from the plant to the extent the power
is not needed for regulated retail service. MidAmerican Energy has made a filing
with the IUB for a certificate to construct this plant and has made a filing
with the IUB for approval of ratemaking principles for this plant during the
fourth quarter of 2002. The development of this plant is subject to obtaining
environmental and other required permits, as well as to receiving orders from
the IUB approving construction of the plant and associated transmission
facilities and establishing ratemaking principles which are satisfactory to
MidAmerican Energy.

The Company's subsidiary, Fox Energy Company LLC, is developing a 635 net
MW gas fired power generating facility in Kaukanna, Outagamie County, Wisconsin.
A subsidiary of TransAlta Corporation has agreed to participate in the
development of this project at a level of 50% and has an option to own 50% of
the project. The Company's subsidiary, CE Obsidian Energy LLC, or Obsidian, is
developing a 185 net MW geothermal facility in Imperial Valley, California,
known as Salton Sea VI. An affiliate of El Paso Corporation, or El Paso, has
elected to participate in the ownership and development of this project at a
level of 50%.

The Company is actively seeking to develop, construct, own and operate
additional new energy projects, both domestically and internationally, the
completion of any of which is subject to substantial risk. Development can
require the Company to expend significant sums for preliminary engineering,
permitting, fuel supply, resource exploration, legal and other expenses in
preparation for competitive bids which the Company may not win or before it can
be determined whether a project is feasible, economically attractive or capable
of being financed. Successful development and construction is contingent upon,
among other things, negotiation on terms satisfactory to the Company of
engineering, construction, fuel supply, sales contracts and, if the Company
intends to own less than 100% of the project, joint venture or similar
agreements, with other project participants, receipt of required governmental
permits and consents and timely implementation of construction. There can be no
assurance that development efforts on any particular project, or the Company's
development efforts generally, will be successful. See "Risk Factors."

COOPER NUCLEAR STATION CONTRACT RESTRUCTURING

On July 31, 2002, MidAmerican Energy and the NPPD signed an agreement on
the restructuring of the power purchase contract for Cooper Nuclear Station.
Under the terms of the restructured contract, MidAmerican Energy will pay NPPD
through December 31, 2004, a scheduled amount per unit for 380 MW of the
accredited capacity of Cooper Nuclear Station and a minimum of approximately 1.2
million MWh in the last five months of 2002 and approximately 2.5 million MWh in
each of 2003 and 2004. NPPD also paid MidAmerican Energy $39.1 million on August
1, 2002.

In December 2000, MidAmerican Energy ceased contributing decommissioning
funds to NPPD and maintained a separate fund for estimated Cooper Nuclear
Station decommissioning costs. Through July 31, 2002, $18.3 million had been
accrued and retained by MidAmerican Energy in this separate fund. In conjunction
with the power purchase contract restructuring, MidAmerican Energy is
recognizing the $39.1 million cash payment and the $18.3 million previously
accrued for decommissioning into income based on the estimated energy expected
to be received for the remainder of the contract.

Finally, both parties agreed to release each other from any and all claims,
past or present, each might have under the power purchase contract prior to
being restructured and file to dismiss the litigation currently pending in U.S.
District Court.

Under the terms of MidAmerican Energy's power purchase contract with NPPD
prior to its restructuring, MidAmerican Energy paid NPPD one-half of the fixed
and operating costs of Cooper Nuclear Station, excluding depreciation but
including debt service, and MidAmerican Energy's share of the nuclear fuel cost,
including Department of Energy disposal fees, based on energy delivered. In
addition, prior to December 2000, MidAmerican Energy contributed toward payment
of one-half of Cooper Nuclear Station's project decommissioning costs based on
an assumed 2004 shutdown of the plant. These obligations ceased pursuant to the
restructuring of the power purchase contract for Cooper Nuclear Station.

OBLIGATIONS AND COMMITMENTS

The Company has contractual obligations and commercial commitments that may
affect its financial condition. Based on management's assessment of the
underlying provisions and circumstances of the material contractual obligations
and commercial commitments of the Company, including material off-balance sheet
and structured finance arrangements, there is no known trend, demand,
commitment, event or uncertainty that is reasonably likely to occur which would
have a material effect on the Company's financial condition or results of
operations. The following tables identify material obligations and commitments
as of December 31, 2001:

PERIOD PAYMENTS ARE DUE
----------------------------------------------------------------------
TOTAL 2002 2003-2004 2005-2006 AFTER 2006
CONTRACTUAL CASH OBLIGATIONS (IN MILLIONS) ------------- ---------- ----------- ----------- -------------

Parent company long-term debt (1) ................. $ 1,850.0 $ -- $ 215.0 $ 260.0 $ 1,375.0
Subsidiary and project debt (1) ................... 5,078.3 317.2 571.6 620.9 3,568.6
Company-obligated mandatorily redeemable
preferred securities of subsidiary trusts ........ 880.3 -- -- 136.4 743.9
Subsidiary-obligated mandatorily redeemable
preferred securities of subsidiary trusts (2)..... 100.0 100.0 -- -- --
Mandatorily redeemable preferred securities
of subsidiaries .................................. 26.7 6.7 13.3 6.7 --
Power purchase contract (3) ....................... 25.9 17.4 8.5 -- --
Coal, electricity and natural gas contract
commitments (4) .................................. 479.4 163.9 207.3 67.9 40.3
Operating leases (4) .............................. 135.6 31.2 46.7 24.2 33.5
---------- ------ --------- --------- ----------
Total ............................................ $ 8,576.2 $ 636.4 $ 1,062.4 $ 1,116.1 $ 5,761.3
========== ======= ========= ========= ==========

- ----------

(1) Excludes unamortized debt premiums and discounts.

(2) These subsidiary-obligated mandatorily redeemable preferred securities of
subsidiary trusts were redeemed on March 11, 2002.

(3) This liability was eliminated with the execution of the Settlement
Agreement and Release related to the restructured Cooper Nuclear Station
power purchase agreement effective August 1, 2002.

(4) The fuel and energy commitments and operating leases are not reflected on
the consolidated balance sheets.

COMMITMENT EXPIRATION PER PERIOD
------------------------------------------------------------------
TOTAL 2002 2003-2004 2005-2006 AFTER 2006
OTHER COMMERCIAL COMMITMENTS (IN MILLIONS) ----------- ---------- ----------- ----------- -----------

Unused parent company revolving lines of
credit ........................................ $ 200.7 $ 86.5 $ 114.2 $ -- $ --
Parent company letters of credit ............... 45.8 -- 45.8 -- --
Unused subsidiary lines of credit .............. 541.8 511.3 30.5 -- --
Parent company guarantee of subsidiary debt..... 176.9 2.1 3.2 3.6 168.0
Subsidiary lines of credit from parent
company ....................................... 10.0 -- -- -- 10.0
-------- ------- -------- ---- ------
Total ......................................... $ 975.7 $ 599.9 $ 193.7 $ 3.6 $ 178.0
======== ======= ======== ===== =======

As of September 30, 2002, Northern Natural Gas had $13.8 million of
obligations to deliver 4.0 Bcf of natural gas in 2002 and $46.0 million of
obligations to deliver 12.2 Bcf of natural gas in 2003. The obligations are
revalued based on market prices for natural gas, with changes in value included
in the statement of operations. In 2002, Northern Natural Gas entered into
natural gas commodity price swaps and index basis swaps to effectively fix the
deferred obligation balance. Any further changes in the market value of the
deferred obligations will be offset by a corresponding change in the opposite
direction in the market value of the swaps.

Other than the delivery of natural gas issue described above, the issuance
of Company-obligated mandatorily redeemable preferred securities of subsidiary
trust in connection with the Northern Natural Gas and Kern River acquisitions as
described in note 2 in the notes to the consolidated financial statements for
the nine months ended September 30, 2002, and the issuance of long-term debt as
described in note 8 in the notes to the consolidated financial statements for
the nine months ended September 30, 2002, there have been no other material
changes to the obligations and commitments as described in the Annual Report on
Form 10-K for the year ended December 31, 2001.

OFF-BALANCE SHEET ARRANGEMENTS

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

As of September 30, 2002, the Company's investments which are accounted for
under the equity method had an aggregate $1,060.2 million of debt and $70.3
million in outstanding letters of credit. As of September 30, 2002, the
Company's pro-rata share of the debt was $524.9 million and was non-recourse to
the Company, except for $138.8 million of such debt which the Company has
guaranteed on the Salton Sea Funding Series F Bonds and which was included in
the Company's consolidated balance sheet at September 30, 2002. (See note 8 to
the notes to the consolidated financial statements for the year ended December
31, 2001 included in this prospectus for further discussion). The Company's
pro-rata share of the outstanding letters of credit was $35.1 million as of
September 30, 2002. The Company is generally not required to support the debt
service obligations of these investments. However, default with respect to this
non-recourse debt could result in a loss of invested equity.

STANDARD ELECTRICITY MARKET DESIGN

transmission and generation facilities designed "to promote economic efficiency"
and replace the "obsolete patchwork we have today," according to the FERC
Chairman. The final rule, if adopted as currently proposed, would require all
public utilities operating transmission facilities subject to the FERC
jurisdiction to file revised open access transmission tariffs that would require
changes to the basic services these public utilities currently provide. The
proposed rule may impact the pricing of MidAmerican Energy's electricity and
transmission products. The FERC does not envision that a final rule will be
fully implemented until September 30, 2004. The Company is still evaluating the
proposed rule and the Company believes that the final rule could vary
considerably from the initial proposal. Accordingly, the Company is presently
unable to quantify the likely impact of the proposed rule on the Company and its
subsidiaries.

DOMESTIC GAS RATES MATTERS

On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting
an increase in rates of approximately $26.6 million for its Iowa retail natural
gas customers. As part of the filing, MidAmerican Energy requested an interim
rate increase of approximately $20.4 million annually. On June 12, 2002, the IUB
issued an order granting an interim rate increase of approximately $13.8 million
annually, effective immediately and subject to refund with interest. On July 15,
2002, MidAmerican Energy and the Office of Consumer Advocate filed a proposed
settlement agreement with the IUB. The settlement agreement, which was approved
by the IUB on November 8, 2002, provides for an increase in rates of $17.7
million annually for MidAmerican Energy's Iowa retail natural gas customers and
freezes such rates for two years after the date the IUB approves tariffs
implementing the settlement agreement. MidAmerican Energy implemented the new
rates effective November 25, 2002.

PHILIPPINES REGULATORY MATTERS

The Philippine Congress has passed the Electric Power Industry Reform Act
of 2001, which is aimed at restructuring the Philippine power industry,
privatization of the NPC and introduction of a competitive electricity market,
among other initiatives. The implementation of the bill may have an impact on
the Company's future operations in the Philippines and the Philippines power
industry as a whole, the effect of which is not yet determinable and estimable.

In connection with an interagency review of approximately 40 independent
power project contracts in the Philippines, the Casecnan Project (along with
four other unrelated projects) has reportedly been identified as raising legal
and financial questions and, with those projects, has been prioritized for
renegotiation. The Company's subsidiaries' Upper Mahiao, Malitbog, and
Mahanagdong projects, which, together with the Casecnan Project, collectively
referred to as the Philippine Projects, have also reportedly been identified as
raising financial questions. No written report has yet been issued with respect
to the interagency review, and the timing and nature of steps, if any, that the
Philippine Government may take in this regard are not known. To the extent
disputes arise under the Philippine Projects' agreements with respect to the
Philippines Projects' obligations, rights and remedies thereunder, such disputes
will be determined by international arbitration in a neutral forum conducted in
accordance with the rules of the International Chamber of Commerce or UNCITRAL,
as applicable.

Representatives of CE Casecnan together with certain current and former
Philippine government officials, also have been requested to appear, and have
appeared, before a Philippine Senate committee which has independently raised
questions and made allegations with respect to the Casecnan Project's tariff
structure and implementation. No further hearings are scheduled at this time.

NEW ACCOUNTING PRONOUNCEMENTS AND REPORTING ISSUES

In August 2001, the Financial Accounting Standards Board, or FASB, issued
SFAS No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143
requires recognition on the balance sheet of legal obligations associated with
the retirement of long-lived assets that result from the acquisition,
construction, development and/or normal operation of such assets. Additionally,
at the time an asset retirement obligation, or ARO, is recognized, an ARO asset
of the same amount is recorded and depreciated. This pronouncement is effective
for fiscal years beginning after June 15, 2002. The Company is evaluating the
impact that adoption of this standard will have on its consolidated financial
statements.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets", which addresses the financial
accounting and reporting for the impairment or disposal of long-lived assets.
The adoption of SFAS No. 144 on January 1, 2002, did not have any impact on the
Company's consolidated financial statements.

The Emerging Issues Task Force, or EITF, recently issued EITF Issue No.
02-3, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts
Under Issues No. 98-10 and 00-17." In accordance with EITF No. 02-3, all gains
and losses on energy trading contracts must be reported net on the income
statement, effective for reporting periods ending after July 15, 2002, with all
prior periods presented being reclassified to a consistent presentation.
MidAmerican Energy's nonregulated wholesale gas and electric marketing
activities qualify as "energy trading" contracts under the guidance of EITF No.
98-10. In accordance with EITF Issue No. 02-3, effective September 30, 2002, for
MidAmerican Energy, all trading revenues are reported net of the cost of such
sales. Previously, such amounts were recorded gross. All prior periods have been
reclassified to conform to the net presentation.

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

During the nine months ended September 30, 2002, the Company issued
long-term debt as described in note 8 of our notes to the consolidated financial
statements for the nine months ended September 30, 2002 and assumed additional
debt with the acquisitions of Northern Natural Gas and Kern River. However, the
Company does not believe it has any material change in regard to exposure to
interest rate risk.

Refer to note 16 of our notes to the consolidated financial statements for
the year ended December 31, 2001 included in this prospectus for discussion on
derivatives used to hedge price risk. The Company's exposure to commodity price
risk has not changed materially from December 31, 2001.

BUSINESS

GENERAL

MidAmerican Energy Holdings Company is a United States-based privately
owned global energy company. Our subsidiaries' principal businesses are
regulated electric and natural gas utilities, regulated interstate natural gas
transmission and electric power generation. Our operations are organized on
seven distinct platforms which we refer to as: MidAmerican Energy, Northern
Natural Gas, Kern River, CE Electric UK (which includes Northern Electric and
Yorkshire Electricity), CalEnergy Generation-Domestic, CalEnergy
Generation-Foreign and HomeServices. Through six of these platforms, we own and
operate a combined electric and natural gas utility company in the United
States, two natural gas pipeline companies in the United States, two electricity
distribution companies in the United Kingdom, and a diversified portfolio of
domestic and international independent power projects. We also own the second
largest residential real estate brokerage firm in the United States.

Financial information for each of our seven operating platforms is
contained in note 22 to our consolidated financial statements for the year ended
December 31, 2001 and note 14 to our consolidated financial statements for the
nine month period ended September 30, 2002 included in this prospectus.
Financial information for Kern River and Northern Natural Gas is included in
note 14 to our consolidated financial statements for the nine month period ended
September 30, 2002, from their respective dates of acquisition. Financial
information for our utility platforms may differ from the amounts included in
the notes to the financial statements due to the effects of fair value
adjustments associated with our acquisition of these entities. The following is
a chart of our operating platforms and the principal lines of business in which
they are engaged:

Our senior unsecured obligations have received investment grade ratings of
Baa3, BBB-- and BBB from Moody's Investors Service Inc., Standard & Poors
Ratings Services and Fitch, Inc., respectively. Our utility subsidiaries also
have investment grade ratings by Moody's, S&P and Fitch, respectively:
MidAmerican Energy (A3, A- and A-), Northern Natural Gas (Baa2, A- and BBB+),
Kern River (A3, A- and A-), Northern Electric (A3, A- and A) and Yorkshire
Electricity (A3, A- and A), respectively. However, these ratings are subject to
change.

We initially incorporated in 1971 under the laws of the State of Delaware.
We were reincorporated in 1999 in Iowa, at which time we changed our name from
CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.

STRATEGY

In order to implement this strategy, we plan to:

PURSUE OPERATING EFFICIENCIES AND INTERNAL INVESTMENT OPPORTUNITIES IN OUR
BUSINESSES, WHILE MAINTAINING QUALITY AND RELIABILITY OF SERVICE. Our management
philosophy emphasizes the efficient operation of our businesses through strict
attention to the operational performance of our assets, continuous review and
implementation of cost reduction initiatives and the active pursuit of
opportunities to earn reasonable returns by making incremental capital
investments within our existing operations. Following each of our utility
acquisitions, we have implemented operational improvements and cost reductions
that have enhanced asset performance and service reliability. These and other
initiatives have helped us to pursue our goal of being a low-cost provider of
energy and energy services to our customers and have strengthened our
competitive position in the marketplace, while also increasing the returns on
our investments. In addition, we have worked closely and successfully with
customers and with regulatory and legislative authorities to ensure that our
business initiatives are consistent with our obligations to serve customers and
with the requirements of the regulatory regimes under which we operate. We have
identified and are proceeding with a number of significant capital investment
opportunities that we believe offer attractive risk-adjusted returns. These
opportunities include a $1.2 billion program to expand MidAmerican Energy's base
of electric generation facilities in Iowa and a $1.2 billion investment in Kern
River's 2003 Expansion Project.

CAPITALIZE ON CHANGE IN OUR INDUSTRY AND ON OUR SUPERIOR ACCESS TO CAPITAL
IN ORDER TO MAKE ATTRACTIVE INVESTMENTS. The global energy markets, particularly
those in the United States, are experiencing a period of significant change due
to various factors, including the macroeconomic environment, fluctuating
commodity prices, regulatory and legislative developments and financial
restructurings by many market participants. We and our shareholders believe that
such an environment provides opportunities for disciplined companies with access
to investment capital to achieve reasonable risk-adjusted returns by acquiring
high quality companies and assets at reasonable prices. Warren Buffett, Chairman
of the Board and Chief Executive Officer of Berkshire Hathaway, has publicly
stated that we are a core holding of Berkshire Hathaway and are expected to be
its principal vehicle for investments in the energy sector. In 2002 to date, we
completed two acquisitions of interstate natural gas transmission pipelines,
which we funded with a majority of the proceeds of Berkshire Hathaway's
investment in $1.273 billion of our trust preferred securities and $402 million
of our zero coupon convertible preferred stock, all of which is subordinated to
our senior indebtedness. We believe that our ability to successfully negotiate
and complete these acquisitions was facilitated by our access to capital from
Berkshire Hathaway and that there continue to be opportunities in the current
environment to make additional acquisitions that further enhance our business
mix, risk profile, capitalization and investment returns.

MAINTAIN PRUDENT FINANCIAL AND RISK MANAGEMENT POLICIES AND PRACTICES.
Through our focus on regulated utility businesses, we strive to minimize the
underlying risks of our portfolio of assets. Substantially all of our net owned
MW in our non-utility power generation business have long-term (greater than one
year) contracts for the sale of their energy and/or capacity, and substantially
all of these assets are financed by non-recourse project finance debt. We seek
to limit our exposure to movements in the commodity prices of energy products
and are not a significant trader of energy commodities. Our activities in the
marketing and supply of energy to customers outside of our regulated customer
base are not a material part of our business and are conducted pursuant to
closely monitored risk management policies and practices that are intended to
minimize our exposure to fluctuations in energy commodity prices and to
counterparty credit risk. A core tenet of our acquisition and investment
philosophy is that we will only pursue opportunities that meet our strict
requirements for an acceptable risk profile and attractive potential cash flow
returns. If we do not believe that such opportunities are available, we prefer
to reduce our acquisition activities and focus on the optimization of our
existing portfolio rather than pursue growth by accepting greater risks or
inferior returns.

MIDAMERICAN ENERGY

MidAmerican Energy is the largest energy company headquartered in Iowa.
MidAmerican Energy is principally engaged in the business of generating,
transmitting, distributing and selling electric energy and in distributing,
selling and transporting natural gas. MidAmerican Energy distributes electricity
at retail in Iowa, Illinois and South Dakota. It also distributes natural gas at
retail in Iowa, Illinois, South Dakota and Nebraska. MidAmerican Energy's
utility operations are providing regulated retail electric service to
approximately 678,000 customers and regulated retail natural gas service to
approximately 653,000 customers. MidAmerican Energy also provides competitive
natural gas service in several Midwestern states and competitive electric
service in Illinois and Ohio.

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

MidAmerican Energy's electric and gas utility operations are conducted
under franchises, certificates, permits and licenses obtained from state and
local authorities. The franchises, with various expiration dates, are typically
for 25-year terms.

MidAmerican Energy has a residential, agricultural, commercial and
diversified industrial customer group, in which no single industry or customer
accounted for more than 4% of its total 2001 electric operating revenues or 4%
of its total 2001 gas operating margin. Among the primary industries served by
MidAmerican Energy are those which are concerned with food products, the
manufacturing, processing and fabrication of primary metals, real estate, farm
and other non-electrical machinery, and cement and gypsum products.

For the nine months ended September 30, 2002, MidAmerican Energy derived
approximately 67% of its gross operating revenues from its electric utility
business, 28% from its gas utility business and 5% from its non-regulated
business activities. For 2001, 2000 and 1999, the corresponding percentages were
56% electric, 37% gas and 7% non-regulated, 53% electric, 41% gas and 6%
non-regulated and 67% electric, 32% gas and 1% non-regulated, respectively. The
change in revenue mix is principally driven by changes in natural gas prices and
seasonality.

There are seasonal variations in MidAmerican Energy's electric and gas
businesses, which are principally related to the use of energy for air
conditioning and heating. In 2001, 38% of MidAmerican Energy's electric utility
revenues were reported in the months of June, July, August and September, and
59% of MidAmerican Energy's gas utility revenues were reported in the months of
January, February, March and December.

ELECTRIC OPERATIONS

The electric utility industry continues to undergo regulatory change.
Traditionally, prices charged by electric utility companies have been regulated
by federal and state commissions and have been based on

cost of service. In recent years, changes have been occurring that move the
electric utility industry toward a more competitive, market-based pricing
environment. These changes may have a significant impact on the way MidAmerican
Energy does business.

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

For the year ended December 31, 2001, regulated electric sales by
MidAmerican Energy by customer class were as follows: 20.6% were to residential
customers, 15.3% were to small general service customers, 25.8% were to large
general service customers, 7.3% were to other customers, and 31.0% were
wholesale sales. For the year ended December 31, 2001, regulated electric sales
by MidAmerican Energy by jurisdiction were as follows: 88.6% to Iowa, 10.6% to
Illinois and 0.8% to South Dakota.

The annual hourly peak demand on MidAmerican Energy's electric system
occurs principally as a result of air conditioning use during the cooling
season. In July 2002, MidAmerican Energy recorded an hourly peak demand of 3,887
MW, which is 54 MW greater than MidAmerican Energy's previous record hourly peak
of 3,833 MW set in 1999.

The following table sets out information concerning MidAmerican Energy's
power generation facilities as of November 1, 2002:

FACILITY
NET
CAPACITY NET MW COMMERCIAL
OPERATING PROJECT (1) (MW) (2) OWNED (2) FUEL LOCATION OPERATION
- ---------------------------------------------- ---------- ----------- --------- ---------- -----------

Council Bluffs Energy Center units 1 & 2 ..... 133 133 Coal Iowa 1954, 1958
Council Bluffs Energy Center unit 3 .......... 690 546 Coal Iowa 1978
Louisa Generation Station .................... 700 616 Coal Iowa 1983
Neal Generation Station units 1 & 2 .......... 435 435 Coal Iowa 1964, 1972
Neal Generation Station unit 3 ............... 515 371 Coal Iowa 1975
Neal Generation Station unit 4 ............... 624 261 Coal Iowa 1979
Ottumwa Generation Station ................... 708 368 Coal Iowa 1981
Quad Cities Generating Station ............... 1,636 409 Nuclear Illinois 1972
Riverside Generation Station ................. 135 135 Coal Iowa 1925-61
Combustion Turbines .......................... 785 785 Gas/Oil Iowa 1969-95
Moline Water Power ........................... 3 3 Hydro Illinois 1970
Portable Power Modules ....................... 56 56 Oil Iowa 2000
----- ---
Total Operating Power Generation
Facilities .................................. 6,420 4,118
PROJECTS UNDER CONSTRUCTION:
- -----------------------------------------------
Greater Des Moines Energy Center ............. 500 500 Gas Iowa 2003-05
----- -----
Total Power Generation Facilities ............ 6,920 4,618
===== =====

- ----------

(1) We operate all such power generation facilities other than Quad Cities
Generating Station and Ottumwa Generation Station.

(2) Represents accredited net generating capability. Actual MW may vary
depending on operating conditions and plant design. Net MW owned indicates
ownership of accredited capacity for the summer of 2002 as approved by the
Mid-Continent Area Power Pool (MAPP).

MidAmerican Energy's accredited net generating capability in the summer of
2002 was 4,724 MW, which included its 4,118 net MW owned and its accredited net
MW capability pursuant to the restructured Cooper Nuclear Station power purchase
agreement for a minimum guaranteed amount of energy from

any source and the Cordova power purchase agreement. Accredited net generating
capability represents the amount of generation available to meet the
requirements on MidAmerican Energy's energy system, including the net amount of
capacity purchases less capacity sales from company-owned generation and
generation under power purchase contracts. The net generating capability at any
time may be less than it would otherwise be due to regulatory restrictions,
fuel restrictions and generating units being temporarily out of service for
inspection, maintenance, refueling or modifications.

MidAmerican Energy has announced plans regarding two electric generating
plants in Iowa. Both plants would provide service to regulated retail
electricity customers and be included in regulated rate base in Iowa, Illinois
and South Dakota. Wholesale sales may also be made from the plants to the extent
the power is not needed for regulated retail service.

The first plant, which is the Greater Des Moines Energy Center described
above, will be a 540 MW (500 MW based on expected accreditation) natural
gas-fired plant with an estimated cost of $415 million. MidAmerican Energy will
own 100% of the plant and will operate it. The plant will be operated in simple
cycle mode during 2003 and 2004, with combined cycle operation commencing in
2005. MidAmerican Energy commenced construction of the plant in 2002 following
receipt of two orders from the IUB. The first order authorized construction of
the plant. The second order, issued May 29, 2002, specified the principles that
will apply to the plant over its life for purposes of Iowa ratemaking and was
sought by MidAmerican Energy to limit regulatory risk.

The second plant is currently under development and is expected to be a 750
MW super-critical-temperature, coal-fired plant fueled with Powder River
low-sulfur coal in Pottawattamie County, Iowa. If constructed, MidAmerican
Energy will operate the plant and expects to own 450 MW of the plant. Municipal,
cooperative and public power utilities will own the remainder, which is a
typical ownership arrangement for large baseload plants in Iowa. MidAmerican
Energy has made a filing with the IUB for a certificate to construct this plant
and has made a filing with the IUB for approval of ratemaking principles for
this second plant during the fourth quarter of 2002. The development of this
plant is subject to obtaining environmental and other required permits, as well
as to receiving orders from the IUB approving construction of the plant and
associated transmission facilities and establishing ratemaking principles which
are satisfactory to MidAmerican Energy.

MidAmerican Energy is interconnected with Iowa utilities and utilities in
neighboring states and is involved in an electric power pooling agreement known
as Mid-Continent Area Power Pool, or MAPP. MAPP is a voluntary association of
electric utilities doing business in Minnesota, Nebraska, North Dakota and the
Canadian provinces of Saskatchewan and Manitoba and portions of Iowa, Montana,
South Dakota and Wisconsin. Its membership also includes power marketers,
regulatory agencies and independent power producers. MAPP facilitates operation
of the transmission system and is responsible for the safety and reliability of
the bulk electric system.

In November 2001, MAPPCOR, the contractor to MAPP, sold its
transmission-related assets to the Midwest Independent Transmission System
Operator, Inc., or Midwest ISO. The Midwest ISO now has responsibility for
administration of MAPP's Open-Access Transmission Tariff.

Each MAPP participant is required to maintain for emergency purposes a net
generating capability reserve of at least 15% above its system peak demand.
MidAmerican Energy's reserve margin at peak demand for 2002 was approximately
22%. However, significantly higher-than-normal temperatures during the cooling
season could cause MidAmerican Energy's reserve to fall below the 15% minimum.
If MidAmerican Energy fails to maintain the appropriate reserve, significant
penalties could be contractually imposed by MAPP.

MidAmerican Energy's transmission system connects its generating facilities
with distribution substations and interconnects with 14 other transmission
providers in Iowa and five adjacent states. Under

normal operating conditions, MidAmerican Energy's transmission system is
unconstrained and has adequate capacity to deliver energy to MidAmerican
Energy's distribution system and to export and import energy with other
interconnected systems.

In December 1999, the FERC issued Order No. 2000 establishing, among other
things, minimum characteristics and functions for regional transmission
organizations. Public utilities that were not a member of an independent system
operator at the time of the order were required to submit a plan by which its
transmission facilities would be transferred to a regional transmission
organization. On September 28, 2001, MidAmerican Energy and five other electric
utilities filed with the FERC a plan to create TRANSLink Transmission Company
LLC, or TRANSLink, and to integrate their electric transmission systems into a
single, coordinated system operating as a for-profit independent transmission
company in conjunction with a FERC-approved regional transmission organization.
On April 25, 2002, the FERC issued an order approving the transfer of control of
MidAmerican Energy's and other utilities' transmission assets to TRANSLink in
conjunction with TRANSLink's participation in the Midwest ISO. Additional state
regulatory approval is required from states in which TRANSLink will be operating
and those applications have not yet been filed. Once filed, MidAmerican Energy
does not anticipate rulings in the state proceedings until some time in 2003.
Transferring operation and control of MidAmerican Energy's transmission assets
to other entities could increase costs for MidAmerican Energy; however, the
actual impact of TRANSLink on MidAmerican Energy's future transmission costs is
not yet known.

GAS OPERATIONS

For the year ended December 31, 2001, regulated gas sales by MidAmerican
Energy, excluding transportation throughput, by customer class were as follows:
34.5% were to residential customers, 18.2% were to small general service
customers, 1.5% were to large general service customers, 1.7% were to other
customers, and 44.1% were wholesale sales. For the year ended December 31, 2001,
regulated gas sales by MidAmerican Energy, excluding transportation throughput,
by jurisdiction were as follows: 78.9% to Iowa, 10.5% to South Dakota, 9.8% to
Illinois, and 0.8% to Nebraska.

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

MidAmerican Energy has rights to firm pipeline capacity to transport gas to
its service territory through direct interconnects to the pipeline systems of
Northern Natural Gas, Natural Gas Pipeline Company of America, Northern Border
Pipeline Company and ANR Pipeline Company. Firm capacity in excess of
MidAmerican Energy's system needs, resulting from differences between the
capacity portfolio and seasonal system demand, can be resold to other companies
to achieve optimum use of the available capacity. Past IUB, and South Dakota
Public Utilities Commission rulings have allowed MidAmerican Energy to retain
30% of Iowa and South Dakota margins, respectively, earned on the resold
capacity, with the remaining 70% being returned to customers through a purchased
gas adjustment clause as described below.

MidAmerican Energy's cost of gas is recovered from customers through
purchased gas adjustment clauses. In 1995, the IUB gave initial approval of
MidAmerican Energy's Incentive Gas Supply Procurement Program. Under the
program, as amended, MidAmerican Energy is required to file with the IUB every
six months a comparison of its gas procurement costs to an index-based and
historical reference price. If MidAmerican Energy's costs of gas for the period
are less or greater than an established tolerance band around the reference
price, then MidAmerican Energy shares a portion of the savings or costs with
customers. In October 2002, the IUB approved a one year extension of the program
through October 31, 2003. A similar program is currently in effect in South
Dakota through October 31, 2005. Since the implementation of the program,
MidAmerican Energy has successfully achieved and shared savings with its natural
gas customers.

MidAmerican Energy utilizes leased gas storage to meet peak day
requirements and to manage the daily changes in demand due to changes in
weather. The storage gas is typically replaced during the summer months. In
addition, MidAmerican Energy also utilizes three liquefied natural gas plants
and two propane-air plants to meet peak day demands.

MidAmerican Energy has strategically built multiple pipeline
interconnections into several of its larger communities. Multiple pipeline
interconnects create competition among pipeline suppliers for transportation
capacity to serve those communities, thus reducing costs. In addition, multiple
pipeline interconnects give MidAmerican Energy the ability to optimize delivery
of the lowest cost supply from the various pipeline supply basins into these
communities and increase delivery reliability. Benefits to MidAmerican Energy's
system customers are shared with all jurisdictions through a consolidated
purchased gas adjustment clause.

NORTHERN NATURAL GAS COMPANY

EXISTING FACILITIES AND BUSINESS

Northern Natural Gas is one of the largest interstate natural gas pipeline
systems in the United States. It reaches from Texas to Michigan's Upper
Peninsula and is engaged in the transmission and storage of natural gas for
utilities, municipalities, other pipeline companies, gas marketers, industrial
and commercial users and other end users. Northern Natural Gas' revenues are
derived from the interstate transportation and storage of natural gas for third
parties. Except for small quantities of natural gas owned for system operations,
Northern Natural Gas does not own the natural gas that is transported through
its system. Northern Natural Gas' transportation and storage operations are
subject to a FERC-regulated tariff that is designed to allow it an opportunity
to recover its costs together with a regulated return on equity.

Northern Natural Gas' system is comprised of two distinct areas, its
traditional end-use and distribution market area at the northern end of the
system, including delivery points in Michigan, Illinois, Iowa, Minnesota,
Kansas, Nebraska, Wisconsin and South Dakota, which we refer to as the Market
Area, and the natural gas supply and market area at the southern end of the
system, including Kansas, Oklahoma, Texas and New Mexico, which we refer to as
the Field Area. Northern Natural Gas' Field Area is interconnected with many
interstate and intrastate pipelines in the national grid system. A majority of
Northern Natural Gas' capacity in both the Market Area and the Field Area is
dedicated to Market Area customers under long-term firm transportation
contracts. Approximately 49% of Northern Natural Gas' capacity subject to firm
transportation contracts is under contracts which extend beyond 2005.

Northern Natural Gas' strategic plan is focused on taking advantage of the
system's bi-directional and relatively flexible natural gas transportation
capabilities and its storage assets to maximize economic returns. A key
component of this strategic plan is to build upon Northern Natural Gas' asset
base located in the center of the North American natural gas grid by increasing
flexibility through additional pipeline interconnects. Through existing
interconnections, Northern Natural Gas' shippers have supply access to Canadian,
Rocky Mountain, Hugoton, Anadarko and Permian supplies. Northern Natural Gas
also expects to pursue selective pipeline expansions, storage service
enhancement and improved utilization of existing systems. In addition, Northern
Natural Gas is focused on utilizing its ability to transport both dry natural
gas and processable natural gas to take advantage of opportunities presented by
natural gas processing facility consolidations in the Mid-continent. Northern
Natural Gas expects to be able to meet the expected demand growth in its Market
Area with only modest investment in new facilities as a result of the
flexibility in Northern Natural Gas' system. Furthermore, Northern Natural Gas'
access to supply diversity is expected to provide it with a significant
competitive advantage because of the ability of the system to provide shippers
access to many sources of low cost natural gas.

Northern Natural Gas operates approximately 16,600 miles of natural gas
pipelines which deliver approximately 5.0% of the total natural gas consumed in
the United States. The Northern Natural Gas system is believed to be the largest
in the United States as measured by pipeline miles and the eighth largest as
measured by throughput. The pipeline system is powered by 92 transmission
compressor stations with an aggregate of approximately 840,000 horsepower.
Northern Natural Gas operates three natural gas storage facilities and two
liquefied natural gas, or LNG, storage peaking units for a total storage
capacity of 59 Bcf and peak delivery capability of over 1.3 Bcf/day. Northern
Natural Gas' pipeline system is configured with approximately 3,500 receipt and
delivery points (excluding farm taps) which are

integrated with the facilities of local distribution companies, or LDCs. Natural
gas deliveries from Northern Natural Gas to the Market Area and Field Area
totaled approximately 1.4 Tcf in 2001.

The northern portion of Northern Natural Gas' pipeline system transports
natural gas primarily to end-user and local distributor markets in the Market
Area. Customers consist of LDCs, municipalities, other pipeline companies, gas
marketers and end-users. While approximately ten large LDCs account for the
majority of Market Area volumes, Northern Natural Gas also serves numerous small
communities through these large LDCs as well as municipalities or smaller LDCs
and directly serves several large end-users. In 2001, approximately 85% of
Northern Natural Gas' revenues were from capacity charges under firm
transportation and storage contracts and approximately 85% of those revenues
were from LDCs. In 2001, approximately 69% of Northern Natural Gas' revenues
were generated from Market Area customer contracts. The following customers, all
of whom were utility LDCs located in the Market Area, each accounted for
approximately 10% or more of Northern Natural Gas' transportation revenues for
the year ended December 31, 2001: Reliant Energy Minnegasco (18%); UtiliCorp
United Inc., now Aquila, Inc. (12%); Northern States Power Company--Minnesota
(10%); and MidAmerican Energy (10%).

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

In the Field Area, customers holding transportation capacity consist of
LDCs, marketers, producers, and end-users. The majority of Northern Natural Gas'
Field Area firm transportation is provided to Northern Natural Gas' Market Area
firm customers under long-term firm transportation contracts with such volumes
supplemented by volumes transported on an interruptible basis or pursuant to
short-term firm contracts. In 2001, approximately 20% of Northern Natural Gas'
revenues were generated from Field Area customer transportation contracts.

Northern Natural Gas' system is characterized by significant seasonal
swings in demand, which provide opportunities to deliver high value-added
services. Because of its location and multiple interconnections with other
interstate and intrastate pipelines, Northern Natural Gas is able to access
natural gas both from traditional production areas, such as the Hugoton, Permian
and Anadarko Basins, as well as growing supply areas such as the Rocky Mountains
through Trailblazer Pipeline Company, Pony Express Pipeline and Colorado
Interstate Gas Company, and from Canadian production areas through Northern
Border Pipeline Company, Great Lakes Gas Transmission Limited Partnership and
Viking Gas Transmission Company. As a result of Northern Natural Gas' geographic
location in the middle of the United States and its many interconnections with
other pipelines, Northern Natural Gas augments its steady end-user and LDC
revenues by taking advantage of opportunities to provide intermediate
transportation through pipeline interconnections for customers in other markets
including Chicago, other parts of the Midwest, Texas and California.

Northern Natural Gas' storage services are provided through the operation
of three underground storage fields (one in Iowa and two in Kansas) and two LNG
storage peaking units. The three underground natural gas storage facilities and
Northern Natural Gas' two LNG storage peaking units have a total storage
capacity of approximately 59 Bcf and over 1.3 Bcf/day of peak day
deliverability. These storage facilities provide Northern Natural Gas with
operational flexibility for daily balancing of its system and providing services
to customers for meeting their year-round loadswing requirements. In 2001,
approximately 11% of Northern Natural Gas' revenues were generated from storage
services.

COMPETITION

Pipelines compete on the basis of cost, flexibility, reliability of service
and overall customer service. Historically, Northern Natural Gas has been able
to provide competitive cost service because of its access to a variety of low
cost supply basins, its cost control measures and its relatively high load
factor through-put, which lowers the cost per unit of transportation. Although
Northern Natural Gas has

experienced pipeline system bypass affecting a small percentage of its market,
to date Northern Natural Gas has been able to more than offset any load lost to
bypass in the Market Area through expansion projects such as the Peak Day 2000
project (described below).

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

Natural gas competes with other forms of energy, including electricity,
coal and fuel oil, primarily on the basis of price. The price of natural gas is
influenced by legislation and governmental regulations, the weather, the futures
market, production costs, and other factors beyond the control of Northern
Natural Gas. Industrial end-users often have the ability to choose from
alternative fuel sources in addition to natural gas, such as fuel oil and coal.
Northern Natural Gas attempts to maintain its competitive position through
discounting transportation to keep delivered natural gas prices in line with
prices for alternative fuels and by using flexible short-term and interruptible
transportation services that are contracted for on an as needed basis.

Northern Natural Gas believes that current and anticipated changes in its
competitive environment have created opportunities to serve existing customers
more efficiently and to meet certain growing supply needs. While LDCs provide
peak day delivery growth driven by population growth and alternative fuel
replacement, new off-peak demand growth is being driven primarily by power and
ethanol plant expansion. Off-peak demand growth is important to Northern Natural
Gas as this demand can generally be satisfied with little or no requirement for
the construction of new facilities. Approximately 3,000 MW of natural gas-fired
electric power plants in development have been announced in close proximity to
Northern Natural Gas' system. Northern Natural Gas has been successful in
competing for a significant amount of the increased demand related to the
construction of new power and ethanol plants. Over the last five years, Northern
Natural Gas has contracted approximately 528 mmcf/day of volume on its system
from such new facilities, of which approximately 346 mmcf/day is currently in
service and approximately 182 mmcf/day is scheduled to begin service between
2002 and 2005.

PIPELINE EXPANSIONS

Northern Natural Gas expects to continue evaluating potential additional
pipeline expansions on an opportunistic basis. Northern Natural Gas recently
completed the final year of its $110 million Peak Day 2000 Project. The Peak Day
2000 Project was designed to serve incremental load over a five-year period
beginning in 1997. The Peak Day 2000 Project consists of pipeline expansion that
added approximately 267 mmcf/day of capacity to serve a portion of the 528
mmcf/day of volume Northern Natural Gas has added to its system in the Market
Area. Northern Natural Gas is currently negotiating precedent agreements with
respect to an approximately $11 million Market Area expansion project, which we
refer to as Project Max. Project Max is projected to provide Northern Natural
Gas with an incremental 135 mmcf/day of capacity, primarily beginning service in
2003, including service to the MidAmerican Energy Greater Des Moines Energy
Center that is currently under construction. Northern Natural Gas has a firm
transportation service agreement with MidAmerican Energy to provide 96 mmcf/day
of capacity to transport volumes to this plant. The plant is capable of taking
up to 180 mmcf/day, all of which can be transported on Northern Natural Gas.

OVERVIEW OF REGULATION AND CONTRACTS

The FERC regulates Northern Natural Gas under the Natural Gas Act, the
Natural Gas Policy Act of 1978 and other applicable statutes and regulations.
The Natural Gas Act grants the FERC authority over the construction and
operation of pipelines and related facilities utilized in the transportation,

storage and sale of natural gas in interstate commerce, including the extension,
enlargement or abandonment of such facilities. The FERC also has authority to
regulate rates for natural gas in interstate commerce. Northern Natural Gas
holds several Certificates of Public Convenience and Necessity issued by the
FERC authorizing Northern Natural Gas to construct, operate and maintain its
pipeline and related facilities and services and to transport and store natural
gas in interstate commerce.

Northern Natural Gas' rates and terms and conditions of service are
regulated by the FERC. FERC regulations and Northern Natural Gas' tariff allow
Northern Natural Gas to charge up to maximum approved rates for particular
services as set forth in its tariff. Northern Natural Gas' rates are designed to
provide it with the ability to recover prudently incurred operations and
maintenance costs, taxes, interest, depreciation and amortization and a
regulated return on equity. Natural gas companies may not grant any undue
preference to any person, or maintain any unreasonable difference in their rates
or other terms of service.

On August 1, 2002, the FERC issued an Order to Respond to Northern Natural
Gas related to Northern Natural Gas' existing $450 million revolving credit
facility and to cash management record keeping by Northern Natural Gas. Pursuant
to a Stipulation and Consent Agreement dated August 8, 2002, Northern Natural
Gas agreed to comply with the FERC's cash management practices and to not
include the costs associated with its existing $450 million revolving credit
facility in any future rate proceeding.

See "Regulation--Northern Natural Gas and Kern River."

TRANSITION SERVICES FROM DYNEGY

When Dynegy Inc. assumed ownership of Northern Natural Gas from Enron Corp.
on February 1, 2002, Enron Operations Services Corp., or EOS, agreed to
temporarily continue to provide certain services which it had previously
provided to operate Northern Natural Gas through a transition services
agreement. These services initially included physical operations, gas logistics,
engineering, financial, accounting and other corporate services required to
maintain and operate the system. Certain of these services, including the
physical operation of the pipeline, were provided through June 30, 2002. Through
January 31, 2003, EOS, pursuant to an assignment of the transition services
agreement from Dynegy to us, is continuing to provide services necessary to
operate the pipeline, including gas logistics, which involves gas nominations,
gas scheduling and gas control and other required services, including
information technology services. Additionally, on July 1, 2002, Dynegy assumed
responsibility for the operations, engineering and corporate functions of
Northern Natural Gas. In connection with our purchase of Northern Natural Gas
from Dynegy on August 16, 2002, Dynegy has agreed to continue to provide limited
support services to Northern Natural Gas pursuant to a new transition services
agreement for a period ending January 31, 2003.

KERN RIVER GAS TRANSMISSION COMPANY

EXISTING FACILITIES AND BUSINESS

Kern River's principal asset is a 926-mile interstate natural gas
transmission pipeline system, with an original approximate capacity of 700
mmcf/day, extending from supply areas in the Rocky Mountains to consuming
markets in Utah, Nevada and California. Following the completion of several
recent expansion projects, including the 2002 expansion project and the
California Action Project, the design capacity of the pipeline is currently
845.5 mmcf/day. Construction of the original pipeline began on January 2, 1991
and was completed in early 1992. Kern River's pipeline is comprised of two
distinguishable sections: the mainline and the common facilities. The 707-mile
mainline section extends from the pipeline's point of origination in Opal,
Wyoming through the Central Rocky Mountains area into Daggett, California and is
owned entirely by Kern River. The common facilities consist of the 219-mile
section of pipeline that extends from Daggett to Bakersfield, California. The
common facilities are jointly owned by Kern River (currently approximately
67.9%) and Mojave Pipeline Company (currently approximately 32.1%), as
tenants-in-common. Kern River's ownership percentage in the common facilities
will increase or decrease pursuant to subsequently completed expansions by the
respective joint owners.

COMPETITION

Generally, Kern River competes on a similar basis as other pipelines as is
discussed above under the heading "Business--Northern Natural Gas Company."
Pipelines compete on the basis of cost, flexibility, reliability of service and
overall customer service. More specifically, Kern River competes with various
interstate pipelines and its shippers in serving the southern California, Las
Vegas and Salt Lake City market areas, in order to market any unsubscribed
capacity and expansion capacity. Kern River provides customers with supply
diversity through pipeline interconnects with Northwest pipeline, the Colorado
Interstate Gas pipeline, the Overland Trail pipeline, and Questar pipeline.
These interconnects allow Kern River to access natural gas reserves in Colorado,
northwestern New Mexico, Wyoming, Utah and the Western Canadian Sedimentary
Basin.

Approximately 100% of Kern River's original pipeline capacity is
contractually committed with 14 extended term rate shippers until September 30,
2011. Beyond that, approximately 84% of the original pipeline capacity is
contractually committed until September 30, 2016. Nearly 100% of the additional
permanent capacity constructed in connection with the 2002 expansion and to be
constructed for the 2003 Expansion Project is contractually committed under 10-
and 15-year agreements.

Even though Kern River does not market natural gas supply, in each market
area the purchaser evaluates the total cost of natural gas supply, including
transportation rates, from each alternative supplier/transporter. Based on
published rates and fuel percentages, we believe Kern River currently has the
lowest transportation costs from well-head to burner tip of any interstate
pipeline serving our direct markets in southern California, with gas
transportation costs of approximately $0.39-0.44/MMBtu compared to approximately
$0.77-$1.10/MMBtu on competing pipelines. There can be no assurance that our
competitors do not or will not charge rates which are discounted to these
published rates, particularly on a short-term basis. The 2003 Expansion Project
shippers' initial tariff rates in the original FERC filing were
$0.57-$0.70/MMBtu. These rates are expected to be reduced in a FERC compliance
filing Kern River is required to make 60 days prior to placing the 2003
Expansion Project in service.

Kern River is the only interstate pipeline that presently delivers natural
gas directly from a gas supply basin into the intrastate California market,
which enables its customers to avoid paying a "rate stack" (i.e., additional
transportation costs attributable to the movement from an interstate system to
an intrastate system within California). We believe that Kern River's rate
structure and access to downstream pipelines/storage facilities and to low-cost
Rocky Mountain gas reserves increases its competitiveness and attractiveness to
end-users. Kern River believes it is advantaged relative to other competing
interstate pipelines because its relatively new pipeline can be expanded at
lower costs than those that apply to other systems. Its levelized rate
structures under expansion rates and settlement rates also provide Kern River's
customers with future rate certainty.

OVERVIEW OF REGULATION AND CONTRACTS

The FERC regulates Kern River under the Natural Gas Act, the Natural Gas
Policy Act of 1978 and other applicable FERC regulations. The Natural Gas Act
grants the FERC authority over the construction and operation of pipelines and
related facilities utilized in the transportation and sale of natural gas in
interstate commerce, including the extension, enlargement, or abandonment of
such facilities, as well as the transportation and wholesale sales of natural
gas. The FERC also has authority to regulate rates for natural gas in interstate
commerce. Kern River holds several Certificates of Public Convenience and
Necessity issued by the FERC authorizing Kern River to construct, operate and
maintain its pipeline and related facilities and to transport natural gas in
interstate commerce.

Kern River's rates, charges and terms and conditions of service are
regulated by the FERC. FERC regulations and Kern River's tariff allow Kern River
to charge up to maximum approved rates for particular services as set forth in
its tariff. Kern River's rates are designed to provide it with the ability to
recover prudently incurred operations and maintenance costs, taxes, interest,
depreciation and amortization and a regulated return on equity. Natural gas
companies may not grant any undue preference to any person, or maintain any
unreasonable difference in their rates or other terms of service.

Kern River's rates are set using a "levelized cost-of-service" methodology
so that the rate is constant over the contract period. This is achieved by using
a FERC-approved depreciation schedule in which depreciation increases as
interest expenses decrease.

When Kern River commenced service in 1992, shippers signed 15-year
long-term firm transportation contracts that were to expire in 2007. Under terms
of a 1995 rate settlement, Kern River agreed that new rates would be filed by
May 1, 1999. Instead of filing a rate case, Kern River negotiated a
"pre-settlement" of the rate case with its shippers. This was approved by the
FERC pursuant to a 1999 rate settlement in Docket No. RP99-274, which included
an agreement for a moratorium on rate cases until May 1, 2002 under which Kern
River may be required to file a rate case by May 1, 2004. In order to reduce
transportation rates further and extend contract terms beyond 2007, Kern River
initiated an open season in October 1998 to measure interest in lower, extended
term rates for extended term contracts. Shippers were offered the choice of new
10- or 15-year contracts (4-9 year extensions of their existing contracts) with
both options starting on October 1, 2001 and expiring on either September 30,
2011 or September 30, 2016. On February 8, 2001 the FERC approved implementation
of the extended term rates. All existing shippers have signed up under the
extended term rates program.

See "Regulation--Northern Natural Gas and Kern River."

KERN RIVER'S 2003 EXPANSION PROJECT

The 2003 Expansion Project includes the primary 2003 Expansion Project and
the High Desert Lateral. Kern River filed for FERC approval of the primary 2003
Expansion Project on August 1, 2001 and the High Desert Lateral on July 18,
2001.

Primary 2003 Expansion Project. Construction commenced on August 6, 2002,
and the primary 2003 Expansion Project is expected to be completed and
operational by May 1, 2003 at a total cost of approximately $1.2 billion. The
primary 2003 Expansion Project is a new parallel 717-mile loop pipeline that
will begin in Lincoln County, Wyoming and terminate in Kern County, California.
The project is designed to more than double the amount of natural gas
transported on the Kern River system. The pipeline will include 36- and 42-inch
diameter pipe, most of which will be laid in the existing Kern River
right-of-way at a 25-foot offset from the existing pipeline, and new above
ground facilities. Three segments along the right-of-way, approximately 205
miles in Utah, Nevada and California, will not require additional pipeline but
will instead be areas where the gas will be compressed and transported through
the existing pipeline. The existing pipeline rights-of-way, compressor
facilities and receipt/delivery facilities will all be utilized by the 2003
Expansion Project, streamlining the permitting, acquisition of rights-of-way and
ultimately the construction and operations of the 2003 Expansion Project.

The primary 2003 Expansion Project includes the construction of three new
compressor stations and the installation of additional compression and other
modifications at six existing facilities. When completed, the Kern River system
will have a summer day design capacity of approximately 1.73 Bcf/day, an
increase of approximately 900 mmcf/day.

Kern River has 18 long-term firm transportation service agreements with 17
shippers for 100% of the primary 2003 Expansion Project's capacity. The term for
all these service agreements is either 10 or 15 years from the date on which
transportation services on the 2003 Expansion Project commence.

In addition to the FERC certificate process discussed above, Kern River
requires several federal and state land use, air, water and other environmental
permits in order to construct and ultimately operate the 2003 Expansion Project.
All required permits have been applied for and have been obtained.

High Desert Lateral. High Desert Power Project, LLC, or High Desert LLC,
has commenced construction of a natural gas-fired 750 MW power plant owned by a
subsidiary of Constellation Energy Group in Victorville, California. High Desert
LLC has advised us that the plant is scheduled to start commercial operation by
July 1, 2003.

The High Desert Lateral is a 32-mile lateral and associated meter stations
designed to transport up to 282 mmcf/day of natural gas to the High Desert power
plant for High Desert LLC's affiliate, Victorville Gas, LLC, from interconnects
with the common facilities and PG&E Corporation near Kramer Junction.

Victorville Gas, LLC will be seeking to acquire gas supply and/or upstream
transportation capacity from shippers on the common facilities. Kern River
began construction on the High Desert Lateral in May 2002 and placed the
facilities in service on August 31, 2002.

2003 Expansion Project Financing. The 2003 Expansion Project will be
financed with 70% debt and 30% equity, consistent with Kern River's existing
capital structure, the application for FERC approval of the 2003 Expansion
Project and the limitations contained in the indenture for Kern River's existing
secured senior notes. On June 21, 2002, Kern River entered into an $875 million
credit facility to fund a portion of the costs of the 2003 Expansion Project and
we issued a completion guarantee in favor of the lenders under that credit
facility. For a more complete description of the Kern River credit facility and
our completion guarantee, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Construction--Kern River's 2003 Expansion
Project Financing."

CE ELECTRIC UK

The business of CE Electric UK consists primarily of the distribution of
electricity in the United Kingdom by Northern Electric and Yorkshire
Electricity.

In February 1997, CE Electric UK Ltd., an indirect wholly owned subsidiary
of CE Electric UK, acquired Northern Electric. Northern Electric was one of the
twelve original United Kingdom regional electric companies which came into
existence in 1990 as a result of the restructuring and subsequent privatization
of the electricity industry that occurred in the United Kingdom. On September
21, 2001, CE Electric UK Ltd. acquired 94.75% of Yorkshire Electricity from
Innogy Holdings plc, or Innogy, and simultaneously sold Northern's electricity
and gas supply and metering businesses to Innogy. We sometimes refer to these
transactions as the Northern Electric/Yorkshire Electricity swap. In August
2002, CE Electric UK acquired the remaining 5.25% of Yorkshire Electricity that
it did not already own from Xcel Energy International, an affiliate of Xcel
Energy Inc.

With the acquisition of Yorkshire Electricity and the disposal of the
electricity and gas supply and metering businesses of Northern Electric and
certain other recent or pending strategic disposals, CE Electric UK is
positioned to continue to bring together the skills and resources of two
neighboring distribution businesses to create one of the largest distribution
companies in the United Kingdom, serving more than 3.6 million customers in an
area of approximately 10,000 square miles. CE Electric UK has also implemented a
number of initiatives which have produced savings in ongoing operating and
capital costs at its businesses.

BUSINESS OF CE ELECTRIC UK

Descriptions of the functional business units of each of Northern
Electric's and Yorkshire Electricity's distribution businesses are set forth
below. For a summary description of the deregulated energy market in the United
Kingdom, see "Regulation--CE Electric UK."

ELECTRICITY DISTRIBUTION

Northern Electric's and Yorkshire Electricity's operations consist
primarily of the distribution of electricity and other auxiliary businesses in
the United Kingdom. Northern Electric's and Yorkshire Electricity's distribution
licensee companies, Northern Electric Distribution Limited, or NED, and
Yorkshire Electricity Distribution plc, or YED, receive electricity from the
national grid transmission system and distribute it to their customers' premises
using their network of transformers, switchgear and cables. Substantially all of
the customers in NED's and YED's distribution service areas are connected to the
NED and YED networks and electricity can only be delivered through their
distribution system, thus providing NED and YED with distribution volume that is
relatively stable from year to year. NED and YED charge fees for the use of the
distribution system to the suppliers of electricity. The suppliers, which
purchase electricity from generators and sell the electricity to end-user
customers, use NED's and YED's distribution networks pursuant to an industry
standard "Uses of System Agreement" which NED and YED separately entered into
with the various suppliers of electricity in their respective distribution
areas.

The fees that may be charged by NED and YED for use of their distribution
systems are controlled by a prescribed formula that limits increases (and may
require decreases) based upon the rate of inflation in the United Kingdom and
other regulatory action. For a more detailed description of this pricing
formula, see "Regulation--CE Electric UK."

At September 30, 2002, NED's and YED's electricity distribution network
(excluding service connections to consumers) on a combined basis included
approximately 31,000 kilometers of overhead lines and approximately 65,000
kilometers of underground cables. In addition to the circuits referred to above,
at September 30, 2002, NED's and YED's distribution facilities also included
approximately 56,600 transformers and approximately 58,000 substations.
Substantially all substations are owned in freehold, and most of the balance are
held on leases which will not expire within 10 years.

UTILITY SERVICES

Integrated Utility Services Limited, or IUS, a subsidiary of Northern
Electric, is an engineering contracting company whose main business is providing
electrical connection services on behalf of NED's and YED's distribution
businesses and providing electrical infrastructure contracting services to third
parties. The acquisition of Yorkshire Electricity by CE Electric UK Ltd. in 2001
has given IUS the opportunity to integrate Yorkshire Electricity's engineering
contracting activities into IUS.

GENERATION

Northern Electric Generation Limited, or Northern Generation, a CE Electric
UK subsidiary, presently maintains ownership interests in TPL.

Teesside Power Limited. TPL owns and operates a 1,875 net MW combined cycle
gas-fired power plant at Wilton in northeast England. Northern Generation owns a
15.4% interest in TPL, but does not operate the plant. The project was initiated
in the early 1990s by Enron and at the time of the Enron bankruptcy filing in
December 2001, Enron, through its subsidiaries, owned a 42.5% interest in the
plant, operated the plant, and contracted to purchase 668 MW of capacity from
the plant. In May 2002, TPL executed a restructuring and stabilization agreement
with its lenders. It is anticipated that there will be no further dividends
arising from this investment and, as a result, Northern Generation wrote off its
equity investment in TPL as of December 31, 2001.

Viking. In October 2002, Northern Generation sold its 50% interest in a
50MW gas fired mid-merit power plant known as Viking, located at Seal Sands in
northeast England, to a subsidiary of Rolls-Royce plc.

RETAIL DISPOSAL

In August 2002, Northern Electric disposed of its non-core business of
selling electrical and gas appliances which had been conducted through Northern
Electric Retail Limited, a subsidiary of CE Electric UK.

GAS EXPLORATION AND PRODUCTION

CE Gas Holdings is a gas exploration and production company which is
focused on developing integrated upstream gas projects. Its upstream gas
business consists of the exploration, development and production, including
transportation and storage, of gas for delivery to a point of sale into either a
gas supply market or a power generation facility.

In May 2002, CE Gas Holdings completed the sale of most of its United
Kingdom natural gas assets to Gaz de France for approximately $200 million (
(pounds sterling)137.0 million). As part of the sale, CE Gas Holdings disposed
of all of its interest in the natural gas-producing fields of Anglia, Johnston,
Schooner and Windermere, each of which is located in the southern basin of the
United Kingdom North Sea. The sale also included all of CE Gas Holdings' rights
in four gas fields in development/construction and three exploration blocks
owned by CE Gas Holdings. CE Gas Holdings retained its 5% working interest in
the Victor Field and its 25% interest in the ETS gas pipeline. During 2001, the
Victor Field produced on average 3.5 mmcf/day of gas, and CE Gas Holdings' share
of the estimated remaining gas reserves in the Victor Field is 7 Bcf.

In addition to retaining its interest in the Victor Field and the ETS
pipeline, CE Gas Holdings retained certain development interests in Poland
(Polish Trough) and Australia (Perth, Bass and Otway Basins). CE Gas Holdings'
interest in the retained fields is estimated to equal approximately 150 Bcf of
gas.

CALENERGY GENERATION--DOMESTIC

OPERATING PROJECTS

We own interests in 15 operating non-utility power projects in the United
States. The following table sets out certain information concerning our domestic
non-utility power projects in operation as of November 1, 2002:

FACILITY
NET CONTRACT
CAPACITY NET MW EXPIRATION
PROJECT (MW)(1) OWNED(1) FUEL LOCATION DATE POWER PURCHASER(2)
- ---------------------------------- ---------- ---------- ------ ------------ -------------- -------------------

Cordova .......................... 537 537 Gas Illinois 2019 El Paso/MEC
Salton Sea I ..................... 10 5 Geo California 2017 Edison
Salton Sea II .................... 20 10 Geo California 2020 Edison
Salton Sea III ................... 50 25 Geo California 2019 Edison
Salton Sea IV .................... 40 20 Geo California 2026 Edison
Salton Sea V ..................... 49 25 Geo California Year-to-year El Paso/Zinc(3)
Vulcan ........................... 34 17 Geo California 2016 Edison
Elmore ........................... 38 19 Geo California 2018 Edison
Leathers ......................... 38 19 Geo California 2019 Edison
Del Ranch ........................ 38 19 Geo California 2019 Edison
CE Turbo ......................... 10 5 Geo California Year-to-year El Paso/Zinc(3)
Saranac .......................... 240 90 Gas New York 2009 NYSEG
Power Resources .................. 200 100 Gas Texas 2003 TXU
Yuma ............................. 50 25 Gas Arizona 2024 SDG&E
Roosevelt Hot Springs(4) ......... 23 17 Geo Utah 2020 UP&L
--- ---
Total CalEnergy Generation--
Domestic Operations ............. 1,377 933
===== ===

- ----------

(1) Actual MW may vary depending on operating and reservoir conditions and
plant design. Facility Net Capacity (in MW) represents facility gross
capacity (in MW) less parasitic load. Parasitic load is electrical output
used by the facility and not made available for sale to utilities or other
outside purchasers. Net MW owned indicates current legal ownership, but, in
some cases, does not reflect the current allocation of partnership
distributions.

(2) Southern California Edison Company; San Diego Gas & Electric Company; Utah
Power & Light Company; New York State Electric & Gas Corporation; TXU
Generation Company LP; Zinc Recovery Project; El Paso Corporation; and
MidAmerican Energy.

(3) Each contract governing power purchases by the Zinc Recovery Project will
expire 33 years from the date of the initial power delivery under such
contract. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Construction--Zinc Recovery Project" and
"Business--CalEnergy Generation--Domestic--Zinc Recovery Project."

(4) Our subsidiary owns an approximately 70% indirect interest in this project
which supplies geothermal steam to a power plant owned by UP&L. We obtained
a cash prepayment under a pre-sale agreement with UP&L whereby UP&L paid in
advance for the steam produced by this steam field.

Cordova Project. Cordova Energy owns a 537 MW gas-fired power plant in the
Quad Cities, Illinois area which we refer to as the Cordova Project. CalEnergy
Generation Operating Company, our indirect wholly owned subsidiary, operates the
Cordova Project. The Cordova Project commenced commercial operations in June
2001. Cordova Energy entered into a power purchase agreement with a unit of El
Paso, under which El Paso will purchase all of the capacity and energy from the
project until December 31, 2019. Cordova Energy has exercised an option to
recall from El Paso 50% of the output through May 14, 2004, reducing El Paso's
purchase obligation to 50% of the output during such period. The recalled output

is being sold to MidAmerican Energy. We are aware there have been public
announcements that El Paso's financial condition has deteriorated as a result
of, among other things, reduced liquidity. We will continue to monitor the
situation.

We have a 50% ownership interest in CE Gen, which has interests in ten
geothermal plants in the Imperial Valley in California (commonly referred to as
the Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV, Salton Sea V,
Vulcan, Elmore, Leathers, Del Ranch and CE Turbo projects), and three natural
gas-fired cogeneration plants (Saranac, Power Resources and Yuma). A subsidiary
of El Paso owns the other 50% ownership interest in CE Gen. An indirect wholly
owned subsidiary of CE Gen operates each of the ten Imperial Valley geothermal
plants and each of the three natural gas-fired cogeneration plants. Each plant
possesses an operating margin that allows for production in excess of the
facility net MW amount listed in the table above. Utilization of this operating
margin is based upon a variety of factors and can be expected to vary between
calendar quarters, under normal operating conditions.

Imperial Valley Projects. Six of the Imperial Valley geothermal plants sell
electricity to Southern California Edison Company, or Edison, under 30-year
Standard Offer No. 4 Agreements, which we refer to as the SO4 Agreements. Under
the SO4 Agreements, Edison is obligated to pay capacity payments, capacity bonus
payments and energy payments. The price for contract capacity payments is fixed
for the life of such SO4 Agreement. The energy payments are based on the cost
Edison avoids by purchasing energy from the projects instead of obtaining the
energy from other sources. This cost is referred to as the Avoided Cost of
Energy.

In June and November 2001, six of these projects entered into agreements
that provide for amended energy payments under the SO4 Agreements. The
amendments provide for fixed energy payments of 5.37 cents per kWh commencing
May 1, 2002 for a five year period in lieu of Edison's Avoided Cost of Energy.
Following the five year period, the energy payments revert to Edison's Avoided
Cost of Energy.

Two of the Imperial Valley projects have negotiated contracts with Edison.
The Salton Sea I contract provides for a capacity payment and energy payment for
the life of the contract. Both payments are based upon an initial value that is
subject to quarterly adjustment by reference to various inflation-related
indices. The Salton Sea IV contract also provides for fixed price capacity
payments for the life of the contract and fixed energy prices, which are
subject, in part, to quarterly adjustment by reference to various
inflation-related indices, through June 20, 2017 (and at Edison's Avoided Cost
of Energy thereafter), and, in part, to Edison's Avoided Cost of Energy.

The Salton Sea V and Turbo projects began operations in 2000 and, when the
Zinc Recovery Project achieves 100% production, the Salton Sea V Project and the
Turbo Project would expect to sell approximately 20 MW to the Zinc Recovery
Project at a price based on market transactions. The remainder is being sold
through other market transactions.

Saranac Project. The Saranac Project is a 240 net MW natural gas-fired
cogeneration facility located in Plattsburgh, New York. The Saranac Project has
entered into a 15-year power purchase agreement with New York State Electric &
Gas Company expiring in 2009. The Saranac Project is a qualifying facility, or
QF, and has entered into 15-year steam purchase agreements with Georgia-Pacific
Corporation and Pactiv Corporation. The Saranac Project has a 15-year natural
gas supply agreement with Shell Canada Limited, to supply 100% of the Saranac
Project's fuel requirements. Each of the Saranac power purchase agreement, the
Saranac steam purchase agreements and the Saranac gas supply agreement contains
rates that are fixed for their respective contract terms. Revenues escalate at a
higher rate than fuel costs. The Saranac partnership is indirectly owned by
subsidiaries of CE Gen, ArcLight Capital Partners LLC and General Electric
Capital Corporation.

Power Resources Project. The Power Resources Project is a 200 net MW
natural gas-fired cogeneration project located near Big Spring, Texas, which has
a 15-year power purchase agreement with TXU Generation Company LP, formerly
known as Texas Utilities Electric Company expiring in 2003. The Power Resources
Project is a QF and has a steam purchase agreement with Alon USA, L.P.

Yuma Project. The Yuma Project is a 50 net MW natural gas-fired
cogeneration project in Yuma, Arizona providing 50 MW of electricity to San
Diego Gas & Electric Company under an existing 30-year power purchase agreement
which expires in 2024. The Yuma project is a QF and has executed steam sales
contracts with an adjacent industrial entity to act as its thermal host.

Roosevelt Hot Springs. One of our subsidiaries operates and owns an
approximately 70% indirect interest in a geothermal steam field which supplies
geothermal steam to a 23 net MW power plant owned by Utah Power & Light Company,
or UP&L, located on the Roosevelt Hot Springs property under a 30-year steam
sales contract expiring in 2020. We obtained a cash prepayment under a pre-sale
agreement with UP&L whereby UP&L paid in advance for the steam produced by the
steam field. We guarantee the performance of this subsidiary. We must make
certain penalty payments to UP&L if the steam produced does not meet certain
quantity and quality requirements.

Zinc Recovery Project. CalEnergy Minerals LLC is constructing the Zinc
Recovery Project which will recover zinc from the geothermal brine. Facilities
are being installed near the Imperial Valley project's sites to extract a zinc
chloride solution from the geothermal brine through an ion exchange process.
This solution will be transported to a central processing plant where zinc
ingots will be produced through solvent extraction, electrowinning and casting
processes. The Zinc Recovery Project is operated by an indirect wholly owned
subsidiary of CE Gen, is designed to have a capacity of approximately 30,000
metric tons per year, and has commenced initial commercial operations in 2002.
The Zinc Recovery Project is expected to be at 100% production in mid- 2003.

DEVELOPMENT PROJECTS

Fox Energy. Our subsidiary, Fox, is developing a 635 net MW gas fired power
generating facility in Kaukanna, Outagamie County, Wisconsin. A subsidiary of
TransAlta Corporation has agreed to participate in the development of this
project at a level of 50% and has an option to own 50% of the project. A
Certificate of Public Convenience and Necessity was issued by the Public Service
Commission of Wisconsin on November 8, 2002. An air permit for construction and
initial operations was issued by the Wisconsin Department of Natural Resources
on November 4, 2000 and such application was deemed complete on April 25, 2002.
A final environmental impact statement was issued by the Wisconsin Department of
Natural Resources on August 19, 2002. Electrical and natural gas interconnection
agreements and a water supply agreement have also been executed for this
project.

Salton Sea VI. Our subsidiary, Obsidian, is developing a 185 net MW
geothermal facility in Imperial Valley, California. Substantially all the output
of the facility will be sold to the Imperial Irrigation District pursuant to a
power purchase agreement. An affiliate of El Paso has elected to participate in
the ownership and development of this project at a level of 50%. On July 29,
2002, Obsidian filed an application for certification seeking approval from the
California Energy Commission to construct and operate the facility.

CALENERGY GENERATION--FOREIGN

The following table sets out information concerning CalEnergy Generation's
principal foreign non-utility power projects in operation as of November 1,
2002:

FACILITY
NET POLITICAL
CAPACITY NET MW COMMERCIAL U.S. $ POWER PURCHASER/ RISK
PROJECT (MW)(1) OWNED(1) FUEL LOCATION OPERATION PAYMENTS GUARANTOR(2) INSURANCE
- ------------------- ---------- ------------ ------- ------------- ------------ ---------- ------------------ ----------

Mahanagdong ....... 165 149 Geo Philippines 1997 Yes PNOC-EDC/ROP Yes
Malitbog .......... 216 216 Geo Philippines 1996-97 Yes PNOC-EDC/ROP Yes
Upper Mahiao ...... 119 119 Geo Philippines 1996 Yes PNOC-EDC/ROP Yes
Casecnan .......... 150 150(3) Hydro Philippines 2001 Yes NIA/ROP Yes
--- ---
Total CalEnergy
Generation--
Foreign
Operations ....... 650 634
=== ===

- ----------

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

(2) PNOC--Energy Development Corporation, or PNOC-EDC, Republic of the
Philippines, or ROP, and NIA (NIA also purchases water from this facility).
The government of the Philippines undertaking supports PNOC-EDC's and NIA's
respective obligations.

(3) Subject to repurchase rights of up to 15% of the project by an initial
minority shareholder and a dispute with the other initial minority
shareholder regarding an additional 15% of the project. Also see "Legal
Proceedings--Casecnan Shareholder Litigation" and note 20 to our
consolidated financial statements for the year ended December 31, 2001 for
a discussion of legal proceedings regarding this ownership interest.

We indirectly own the Upper Mahiao, Malitbog and Mahanagdong projects,
which are geothermal power plants located on the island of Leyte in the
Philippines, and the Casecnan Project, a combined irrigation and hydroelectric
power generation project, which is located in the central part of Island of
Luzon in the Philippines. One of our indirect wholly owned subsidiaries operates
each of these projects. Each plant possesses an operating margin that allows for
production in excess of the amount listed above. Utilization of this operating
margin is based upon a variety of factors and can be expected to vary between
calendar quarters, under normal operating conditions.

Mahanagdong. The Mahanagdong Project is a 165 net MW geothermal power
project owned and operated by CE Luzon Geothermal Power Company, Inc., or CE
Luzon, a Philippine corporation of which we indirectly own 100% of the common
stock. Another industrial company owns an approximate 10% preferred equity
interest in the Mahanagdong Project. The Mahanagdong Project has been in
commercial operation since July 25, 1997. The Mahanagdong Project sells 100% of
its capacity on a similar basis as described above for the Upper Mahiao Project
to PNOC-EDC, which in turn sells the power to the NPC for distribution on the
island of Luzon.

The terms of the Mahanagdong energy conversion agreement are substantially
similar to those of the Upper Mahiao agreement. The Mahanagdong agreement
provides for a ten-year cooperation period. At the end of the cooperation
period, the facility will be transferred to PNOC-EDC at no cost. All of
PNOC-EDC's obligations under the Mahanagdong agreement are supported by the
Republic of the Philippines through a performance undertaking. The capacity fees
are approximately 97% of total revenues at the design capacity levels and the
energy fees are approximately 3% of such total revenues. PNOC-EDC's payment
requirements, and its other obligations under the Mahanagdong agreement, are
supported by the Republic of the Philippines through a performance undertaking.

Malitbog. The Malitbog Project is a 216 net MW geothermal project owned and
operated by Visayas Geothermal Power Company, or VGPC, a Philippine general
partnership that is wholly owned, indirectly, by us. The three units of the
Malitbog facility were put into commercial operation on July 25, 1996 (for Unit
I) and July 25, 1997 (for Units II and III). VGPC sells 100% of its capacity on
substantially the same basis as described above for the Upper Mahiao Project to
PNOC-EDC, which sells the power to the NPC for distribution on the islands of
Cebu and Luzon.

The electrical energy produced by the facility is sold to PNOC-EDC on a
take-or-pay basis. These capacity payments equal approximately 100% of total
revenues. A substantial majority of the capacity payments are required to be
made by PNOC-EDC in dollars. The portion of capacity payments payable to
PNOC-EDC in pesos is expected to vary over the term of the Malitbog energy
conversion agreement from 10% of VGPC's revenues in the early years of the
10-year cooperation period to 23% of VGPC's revenues at the end of the
cooperation period. Payments made in pesos will generally be made to a
peso-dominated account and will be used to pay peso-denominated operation and
maintenance expenses with respect to the Malitbog Project and Philippine
withholding taxes, if any, on the Malitbog Project's debt service. The
government of the Philippines has entered into a performance undertaking, which
provides that all of PNOC-EDC's obligations pursuant to the Malitbog energy
conversion agreement carry the full faith and credit of, and are affirmed and
guaranteed by, the Republic of the Philippines.

The Malitbog energy conversion agreement cooperation period expires ten
years after the date of commencement of commercial operation of Unit III. At the
end of this cooperation period, the facility will be transferred to PNOC-EDC at
no cost, on an "as is" basis. See "Legal Proceedings" for a description of legal
proceedings related to the Malitbog Project.

Upper Mahiao. The Upper Mahiao facility is a 119 net MW geothermal power
project owned and operated by CE Cebu Geothermal Power Company, Inc., or CE
Cebu, a Philippine corporation that is 100% indirectly owned by us. The Upper
Mahiao facility has been in commercial operation since June 17, 1996.

Under the terms of the Upper Mahiao energy conversion agreement, CE Cebu
owns and operates the Upper Mahiao Project during the ten-year cooperation
period, which commenced in June 1996, after which ownership will be transferred
to PNOC-Energy Development Corporation, or PNOC-EDC, at no cost.

The Upper Mahiao Project is located on land provided by PNOC-EDC at no
cost. The project takes geothermal steam and fluid, also provided by PNOC-EDC at
no cost, and converts its thermal energy into electrical energy which is sold to
PNOC-EDC on a "take-or-pay" basis, which in turn sells the power to the NPC, for
distribution on the island of Cebu. PNOC-EDC pays to CE Cebu a fee based on the
plant capacity nominated to PNOC-EDC in any year (which, at the plant's design
capacity, is approximately 95% of total contract revenues) and a fee based on
the electricity actually delivered to PNOC-EDC (approximately 5% of total
contract revenues). Payments under the Upper Mahiao agreement are denominated in
U.S. dollars, or computed in U.S. dollars and paid in Philippine pesos at the
then-current exchange rate, except for the energy fee. PNOC-EDC's payment
requirements, and its other obligations under the Upper Mahiao agreement, are
supported by the Republic of the Philippines through a performance undertaking.

Casecnan. CE Casecnan, our indirectly majority owned subsidiary, operates
the Casecnan Project, a combined irrigation and 150 net MW hydroelectric power
generation project. The Casecnan Project consists generally of diversion
structures in the Casecnan and Taan Rivers that captures and diverts excess
water in the Casecnan watershed by means of concrete, in-stream diversion weirs
and transfers that water through a transbasin tunnel of approximately 23
kilometers (including the intake audit from the Taan to the Casecnan River),
with a diameter of approximately 6.5 meters to an existing underutilized water
storage reservoir at Pantabangan. During the water transfer, the elevation
differences between the two watersheds allows electrical energy to be generated
at a 150 net MW rated capacity power plant, which is located in an underground
powerhouse cavern at the end of the water tunnel. A tailrace discharge tunnel of
approximately three kilometers delivers water from the water tunnel and the
powerhouse to the Pantabangan Reservoir, providing additional water for
irrigation and increasing the potential electrical generation at two downstream
existing hydroelectric facilities of the NPC, the government-owned and
controlled corporation that is the primary supplier of electricity in the
Philippines.

CE Casecnan constructed the Casecnan Project under the terms of the project
agreement between CE Casecnan and NIA. Under the project agreement, CE Casecnan
developed, financed and arranged for the construction of the Casecnan Project,
and will own and operate the Casecnan Project for 20 years. During this
cooperation period, NIA is obligated to accept all deliveries of water and
energy, and so long as the Casecnan Project is physically capable of operating
and delivering in accordance with agreed levels set forth in the project
agreement, NIA will pay CE Casecnan a fixed fee for the delivery of a minimum
volume of water and a fixed fee for the delivery of a minimum amount of
electricity. In addition, NIA will pay a fee for all electricity delivered in
excess of a threshold amount up to a specified amount. NIA will sell the
electricity it purchases to the NPC, although NIA's obligations to CE Casecnan
under the project agreement are not dependent on the NPC's purchase of the
electricity from NIA. All fees to be paid by NIA to CE Casecnan are payable in
U.S. dollars. The fixed fees for the delivery of water and energy, regardless of
the amount of electricity or water actually delivered, are expected to provide
approximately 78% of CE Casecnan's revenues. At the end of the cooperation
period, the Casecnan Project will be transferred to NIA and the NPC for no
additional consideration on an "as is" basis.

The Republic of the Philippines has provided a performance undertaking
under which NIA's obligations under the project agreement are guaranteed by the
full faith and credit of the Republic of the Philippines. See "Legal
Proceedings" for a description of legal proceedings related to the Casecnan
Project.

HOMESERVICES

HomeServices of America, Inc., or HomeServices, our wholly owned
subsidiary, is the second largest full-service independent residential real
estate brokerage firm in the United States based on aggregate closed transaction
sides. Closed transaction sides mean either the buy side or sell side of any
closed home purchase and is the standard term used by industry participants and
publications to rank real estate brokerage firms. In addition to providing
traditional residential real estate brokerage services, HomeServices offers
other integrated real estate services, including mortgage originations, title
and closing services and other related services. HomeServices currently operates
in 15 states under the following brand names: Carol Jones Realty, CBSHOME Real
Estate, Champion Realty, Edina Realty, First Realty/GMAC, Iowa Realty, Jenny
Pruitt and Associates REALTORS, Long Realty, Prudential California Realty,
Realty South, Reece & Nichols, Semonin REALTORS and Woods Bros. Realty.
HomeServices generally occupies the number one or number two market share
position in each of its major markets based on aggregate closed transaction
sides. HomeServices' major markets consist of the following metropolitan areas:
Minneapolis and St. Paul, Minnesota; Los Angeles and San Diego, California;
Kansas City, Kansas; Des Moines, Iowa; Omaha and Lincoln, Nebraska; Birmingham,
Alabama; Tucson, Arizona; Louisville, Kentucky; Annapolis, Maryland; Atlanta,
Georgia and Springfield, Missouri.

REAL ESTATE COMPANIES 2002 ACQUISITIONS

In 2002, HomeServices separately acquired three real estate companies for
an aggregate purchase price of approximately $100 million, net of cash acquired,
plus working capital and certain other adjustments. For the year ended December
31, 2001, these real estate companies had combined revenue of approximately $356
million on 42,000 closed sides representing $13.7 billion of sales volume.
Additionally, HomeServices is obligated to pay a maximum earnout of $18.5
million calculated based on 2002 financial performance measures. These purchases
were financed using HomeServices' $65 million revolving credit facility and our
corporate revolver for $40 million, which was contributed to HomeServices as
equity. We are in the process of completing the allocation of the purchase
prices to the assets and liabilities acquired.

PROPERTIES

Our utility properties consist of physical assets necessary and appropriate
to render electric and gas service in our service territories. Electric property
consists primarily of generation, transmission and distribution facilities. Gas
property consists primarily of distribution plants, natural gas pipelines,
related rights-of-way, compressor stations and meter stations. It is the opinion
of management that the principal depreciable properties owned by us are in good
operating condition and well maintained.

MIDAMERICAN ENERGY

MidAmerican Energy's most significant properties are its electric
generation facilities. For a discussion of these generation facilities, please
see "Business--MidAmerican Energy." At September 30, 2002, the electric
transmission system of MidAmerican Energy included approximately 900 miles of
345-kV lines, and 1,325 miles of 161-kV lines. The gas distribution facilities
of MidAmerican Energy at September 30, 2002 included approximately 20,600 miles
of gas mains and services. Substantially all of the former Iowa-Illinois Gas and
Electric Company (predecessor to MidAmerican Energy Company) utility property
and franchises, and substantially all of the former Midwest Power Systems Inc.
(predecessor to MidAmerican Energy Company) electric utility property located in
Iowa, or approximately 79% of gross utility plant, is pledged to secure mortgage
bonds. In addition to the circuits referred to above, at September 30, 2002,
MidAmerican Energy's delivery facilities also included approximately 218,000
distribution transformers and approximately 370 substations.

NORTHERN NATURAL GAS AND KERN RIVER

At September 30, 2002, Northern Natural Gas' system was comprised of
approximately 7,300 miles of mainline transmission pipes and approximately 9,300
miles of smaller diameter branch lines and laterals. Northern Natural Gas'
storage services are provided through the operation of three underground storage
fields, in Redfield, Iowa, and Lyons and Cunningham, Kansas. The three
underground natural gas storage facilities and Northern Natural Gas' two
liquefied natural gas storage peaking units have a total storage capacity of
approximately 59 Bcf. Northern Natural Gas' two LNG liquefaction/vaporization
facilities are located near Garner, Iowa and Wrenshall, Minnesota with storage
capacity of 2 Bcf each.

At September 30, 2002, Kern River's pipeline was comprised of two
distinguishable sections: the mainline and the common facilities. The 707-mile
mainline section extends from the pipeline's point of origination in Opal,
Wyoming through the Central Rocky Mountains area into Daggett, California and is
owned entirely by Kern River. The common facilities consist of the 219-mile
section of pipeline that extends from Daggett to Bakersfield, California. The
common facilities are jointly owned by Kern River (currently approximately
67.9%) and Mojave Pipeline Company (currently approximately 32.1%) as
tenants-in-common.

The right to construct and operate the pipelines across certain property
was obtained through negotiations and through the exercise of the power of
eminent domain, where necessary. Northern Natural Gas and Kern River continue to
have the power of eminent domain in each of the states in which they operate
their respective pipelines, but they do not have the power of eminent domain
with respect to Native American tribal lands. Although the main Kern River
pipeline crosses the Moapa Indian Reservation, all facilities are located within
a utility corridor that is reserved to the United States Department of Interior,
Bureau of Land Management.

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

We believe that Northern Natural Gas and Kern River each have satisfactory
title to all of the real property making up their respective pipelines in all
material respects.

CE ELECTRIC UK

At September 30, 2002, Northern Electric's and Yorkshire Electricity's
electricity distribution networks (excluding service connection to consumers) on
a combined basis included approximately 31,000 kilometers of overhead lines and
approximately 65,000 kilometers of underground cables. In addition to the
circuits referred to above, at September 30, 2002, Northern Electric's and
Yorkshire Electricity's distribution facilities also included approximately
56,600 transformers and approximately 58,000 substations.

OTHER PROPERTIES

At September 30, 2002, our most significant physical properties, other than
those owned by MidAmerican Energy, Northern Natural Gas, Kern River and CE
Electric UK, are our current interests in operating power facilities and our
plants under construction and related real property interests, as well as leases
of office space for our residential real estate brokerage operations. See
"Business" for further detail.

REGULATION

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

MIDAMERICAN ENERGY

MidAmerican Energy is subject to comprehensive regulation by utility
regulatory agencies in Iowa, Illinois and South Dakota that significantly
influences the operating environment and the recoverability of costs from
utility customers. Except for Illinois, that regulatory environment has to date,
in general, given MidAmerican Energy an exclusive right to serve electricity
customers within its service territory and, in turn, the obligation to provide
electric service to those customers. In Illinois all customers are free to
choose their electricity provider. MidAmerican Energy has an obligation to serve
customers at regulated rates that leave MidAmerican Energy's system, but later
choose to return. To date, there has been no significant loss of customers from
MidAmerican Energy's existing regulated Illinois rates.

In connection with the March 1999 approval by the IUB of the MidAmerican
Energy acquisition and March 2000 affirmation as part of our acquisition by a
private investor group, we agreed, among other things, to use all commercially
reasonable efforts to maintain an investment grade credit rating for MidAmerican
Energy's utility operations and its long-term debt and to seek the approval of
the IUB of a reasonable utility capital structure if MidAmerican Energy's
utility operations' common equity level decreases below 42%, excluding
circumstances beyond its control, or below 39%, under any circumstances.
MidAmerican Energy's utility operations' common equity level at December 31,
2001 and September 30, 2002 was above these levels.

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

In December 1999, the FERC issued Order No. 2000 establishing among other
things minimum characteristics and functions for regional transmission
organizations. Public utilities that were not a member of an independent system
operator at the time of the order were required to submit a plan by which their
transmission facilities would be transferred to a regional transmission
organization. On September 28, 2001, MidAmerican Energy and five other electric
utilities filed with the FERC a plan to create TRANSLink Transmission Company
LLC and to integrate their electric transmission systems into a single,
coordinated system operating as a for-profit independent transmission company in
conjunction with a FERC approved regional transmission organization. On April
25, 2002, the FERC issued an order approving the transfer of control of
MidAmerican Energy's and other utilities' transmission assets to TRANSLink in
conjunction with TRANSLink's participation in the Midwest ISO. Additionally,
state regulatory approval is required from states in which TRANSLink will be
operating and those applications have not yet been filed. Once filed,
MidAmerican Energy does not anticipate rulings in the state proceedings until
some time in 2003. Transferring operation and control of MidAmerican Energy's
transmission assets to other entities could increase costs for MidAmerican
Energy; however, the actual impact of TRANSLink on MidAmerican Energy's future
transmission costs is not yet known.

On July 31, 2002, the FERC issued a notice of proposed rulemaking with
respect to Standard Market Design for the electric industry. The FERC has
characterized the proposal as portending "sweeping changes" to the use and
expansion of the interstate transmission and the wholesale bulk power systems in
the United States. The proposal includes numerous proposed changes to the
current regulation of transmission and generation facilities designed "to
promote economic efficiency" and replace the "obsolete patchwork we have today,"
according to the FERC's chairman. The final rule, if adopted as currently
proposed, would require all public utilities operating transmission facilities
subject to the FERC jurisdiction to file revised open access transmission
tariffs that would require changes to the basic services these public utilities
currently provide. The proposed rule may impact the costs and/or pricing of
MidAmerican Energy's electricity and transmission products. The FERC does not
envision that a final rule will be fully implemented until September 30, 2004.
We are still evaluating the proposed rule, and we

believe that the final rule could vary considerably from the initial proposal.
Accordingly, we are presently unable to quantify the likely impact of the
proposed rule on us.

The structure of such federal and state energy regulations have in the
past, and may in the future, be the subject of various challenges and
restructuring proposals by utilities and other industry participants. The
implementation of regulatory changes in response to such changes or
restructuring proposals, or otherwise imposing more comprehensive or stringent
requirements on us, which would result in increased compliance costs, could have
a material adverse effect on our results of operations.

Under a settlement agreement approved by the IUB on December 21, 2001,
MidAmerican Energy's Iowa retail rates in effect on December 31, 2000 are frozen
through December 31, 2005. Additionally, this settlement agreement reinstates,
with modifications, the revenue sharing provisions of a 1997 pricing plan
settlement agreement, which expired on December 31, 2000. The settlement
agreement further provides that an amount equal to 50% of revenues associated
with Iowa retail electric returns on equity between 12% and 14%, and 83.33% of
revenues associated with Iowa retail electric returns on equity above 14%, in
each year will be recorded as a regulatory liability to be used to offset a
portion of the cost to Iowa customers of future generating plant investment. An
amount equal to the regulatory liability will be recorded as a regulatory charge
in depreciation and amortization expense when the liability is accrued. Interest
expense is accrued on the portion of the regulatory liability related to prior
years. Beginning in 2002, the liability is being reduced as it is credited
against allowance for funds used during construction or capitalized financing
costs associated with generating plant additions. As of September 30, 2002, the
related regulatory liability was $95.0 million. In Iowa, MidAmerican Energy does
not have an energy adjustment clause, so any significant increase in fuel costs
or purchased power costs could have a negative impact on MidAmerican Energy.

Under an Illinois restructuring law enacted in 1997, as amended in 2002, a
sharing mechanism is in place for MidAmerican Energy's Illinois regulated retail
electric operations whereby earnings above a computed level of return on common
equity will be shared equally between customers and MidAmerican Energy.
MidAmerican Energy's computed level of return on common equity is based on a
rolling two-year average of the Monthly Treasury Long-Term Average Rate, as
published by the Federal Reserve System, plus a premium of 8.5% for 2000 through
2004 and a premium of 12.5% for 2005 and 2006. The two-year average above which
sharing must occur for 2001 was 14.34%. The law allows MidAmerican Energy to
mitigate the sharing of earnings above the threshold return on common equity
through accelerated recovery of regulatory assets.

On September 21, 2001, MidAmerican Energy filed a petition with the South
Dakota Public Utilities Commission, or SDPUC, to increase its South Dakota
natural gas rates. On February 20, 2002, the SDPUC approved a settlement
agreement allowing increased rates of $3.1 million annually.

On October 19, 2001, MidAmerican Energy filed a petition with the Illinois
Commerce Commission to increase its Illinois natural gas rates. On September 11,
2002, the Illinois Commerce Commission issued an order granting MidAmerican
Energy a $2.2 million annual increase in rates.

On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting
an increase in rates of approximately $26.6 million for its Iowa retail natural
gas customers. As part of the filing, MidAmerican Energy requested an interim
rate increase of approximately $20.4 million annually. On June 12, 2002, the IUB
issued an order granting MidAmerican Energy an interim increase of approximately
$13.8 million annually, effective immediately and subject to refund with
interest. On July 15, 2002 MidAmerican Energy and the Office of Consumer
Advocate filed a proposed settlement agreement with the IUB. The settlement
agreement, which was approved by the IUB on November 8, 2002, provides for an
increase in rates of $17.7 million annually for MidAmerican Energy's Iowa retail
natural gas customers and freezes such rates for two years after the date the
IUB approves tariffs implementing the settlement agreement. MidAmerican Energy
implemented the new rates effective November 25, 2002.

NORTHERN NATURAL GAS AND KERN RIVER

Northern Natural Gas and Kern River are subject to regulation by various
federal and state agencies as discussed below.

As owners of interstate natural gas pipelines, Northern Natural Gas' and
Kern River's rates, services and operations are subject to regulation by the
FERC. The FERC administers, among other things, the Natural Gas Act and the
Natural Gas Policy Act. Additionally, interstate pipeline companies are subject
to regulation by the Department of Transportation pursuant to the Natural Gas
Pipeline Safety Act, which establishes safety requirements in the design,
construction, operations and maintenance of interstate natural gas transmission
facilities.

The FERC has jurisdiction over, among other things, the construction and
operation of pipelines and related facilities used in the transportation,
storage and sale of natural gas in interstate commerce, including the extension,
enlargement or abandonment of such facilities. The FERC also has jurisdiction
over the rates and charges and terms and conditions of service for the
transportation of natural gas in interstate commerce. Our pipeline subsidiaries
also are required to file with the FERC an annual report on Form 2, which is
publicly available, disclosing general corporate information and financial
statements regarding our pipeline subsidiaries.

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

Northern Natural Gas' current tariff structure provides for:

o seasonality in demand rates;

o extension of the majority of firm storage and transport contracts
through May 31, 2003 and October 31, 2003, respectively;

o a rate moratorium through October 31, 2003, with limited re-openers
based on the FERC's rulemaking changes; and

o the right of Northern Natural Gas to file for term-differentiated
rates, if allowed.

Northern Natural Gas' tariff rates were designed to recover a cost of
service that would reflect a 12.3% return on equity based upon the settlement
reached in FERC Docket No. RP 98-203. Northern Natural Gas' last rate case was
filed on May 1, 1998, and its next rate case may be filed no earlier than May
2003 and no later than May 2004. Northern Natural Gas' most likely next rate
case filing date is May 1, 2003 with filed rates to be effective November 1,
2003.

Kern River's tariff rates were designed to recover a cost of service that
would reflect a 13.25% return on equity. Kern River's rates are set using a
"levelized cost-of-service" methodology so that the rate is constant over the
contract period. This is achieved by using a FERC-approved depreciation schedule
in which depreciation increases as interest expense decreases.

In 2000, the FERC issued new rules with respect to terms and conditions of
interstate pipeline transportation service pursuant to Order No. 637. In Order
No. 637, the FERC made changes to its regulatory model to enhance the
effectiveness and efficiency of gas markets as they evolved since the series of
FERC orders commonly referred to as Order No. 636, which were adopted beginning
in the early 1990s and which provided for the restructuring of interstate
pipeline sales and services. Specifically, in Order No. 637 the FERC:

o addressed alternatives to traditional pipeline pricing by permitting
peak/off-peak and term differentiated rate structures;

o revised certain reporting requirements; and

o made changes in regulations related to (1) scheduling equality for
released capacity, (2) capacity segmentations, and (3) pipeline
imbalance services, operational flow orders and penalties.

On July 17, 2000, Northern Natural Gas made its initial compliance filing
in accordance with the FERC's Order No. 637. Northern Natural Gas made a revised
Order No. 637 compliance filing on March 4, 2002 and a supplemental filing on
May 10, 2002. On November 21, 2002, the FERC issued an Order on Compliance with
Order Nos. 637, 587-G and 587-L. In the November 21, 2002 Order, the FERC found
that Northern Natural Gas generally complied with Order Nos. 637, 587-G and
587-L, subject to certain modifications, and ordered Northern Natural Gas to
file compliance tariffs within 30 days.

On June 15, 2000, Kern River filed pro forma tariff sheets in Docket No.
RP00-337 to comply with the FERC's directives in Order No. 637. In its May 30,
2002 "Order on Compliance with Order No. 637 and Second Order on Compliance with
Order Nos. 587-G and 587-L," the FERC found that Kern River had generally
complied with the requirements of Order Nos. 637, 587-G and 587-L, subject to
the certain modifications.

On October 31, 2002, the FERC issued an order that generally accepted Kern
River's tariff filings to comply with Order Nos. 637, 587-G and 587-L. In the
order, the FERC directed Kern River to provide a park and loan service and to
make changes addressing segmentation as well as forward and backhaul
nominations.

On June 28, 2002, Kern River filed tariff sheets to comply with the FERC's
order. These tariff sheets are pending action by the FERC. On September 30,
2002, the FERC issued an order on Kern River's compliance filing with Order No.
587-0. The FERC found that Kern River generally complied with the requirements
of Order No. 587-0 and that Kern River should refile its title transfer tracking
service.

As a result of the FERC's policies favoring competition in gas markets and
the expansion of existing pipelines and construction of new pipelines, the
interstate pipeline industry has begun to experience some turnback of firm
capacity as existing transportation service agreements expire and are
terminated. LDCs and end-use customers have more choices in the new, more
competitive environment and may be able to shift load from one pipeline to
another. If a pipeline experiences capacity turnback and is unable to remarket
the capacity, the pipeline or its other customers may have to bear the costs
associated with the capacity that is turned back. These issues will be resolved
in a pipeline's general rate case proceedings.

The FERC also has authority over gas pipelines' accounting practices. The
FERC recently issued a notice of proposed rulemaking regarding gas accounting
issues which would limit the ability of gas pipelines to enter into cash
management agreements with their parent companies. We are in the process of
reviewing such proposed rule, but we do not believe the rule will have a
material adverse impact on us and our pipeline subsidiaries. See
"Business--Northern Natural Gas Company--Overview of Regulation and Contracts"
and "Business--Kern River Gas Transmission Company--Overview of Regulation and
Contracts."

Additional proposals and proceedings that might affect the interstate
pipeline industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. In some states various forms of restructuring
legislation have been passed and in many states local utility regulatory
agencies are overseeing the restructuring. As a result of restructuring, LDCs
could unbundle their services and withdraw from all or part of their merchant
function, and electric utilities could divest their generating function. This
restructuring would result in the interstate pipelines having different customer
profiles, including independent gas marketers and independent power generators
and end-users. We cannot predict when or if any new proposals might be
implemented or, if so, how Northern Natural Gas and Kern River might be
affected.

OTHER UNITED STATES REGULATION

The Public Utility Regulatory Policies Act of 1978, as amended, or PURPA,
and PUHCA are two of the laws (including the regulations thereunder) that affect
our and certain of our subsidiaries' operations. PURPA provides to QFs certain
exemptions from federal and state laws and regulations, including
organizational, rate and financial regulation. PUHCA extensively regulates and
restricts the activities of registered public utility holding companies and
their subsidiaries. Congress is currently considering major changes to both
PUHCA and PURPA in a House-Senate conference on a comprehensive energy bill
(H.R. 4). The Senate version of the bill (S. 517) would repeal PUHCA and replace
it with provisions giving state and federal regulators enhanced access to the
books and records of all utility holding companies. The Senate bill would also
prospectively repeal PURPA's mandatory purchase obligation for utilities, but
this provision would not abrogate CalEnergy Generation-Domestic's existing QF
contracts. Any such legislation, if adopted, could vary considerably from the
terms contained in either or both of the House and Senate versions which are
presently under consideration. We believe that if the current proposed
legislation is passed, it would apply to new projects only and thus, although
potentially

impacting our ability to develop new domestic projects, it would not affect our
existing qualifying facilities. We cannot assure you, however, that
legislation, if passed, or any other similar legislation proposed in the
future, would not adversely impact our existing domestic projects.

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

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

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

CE ELECTRIC UK

Since 1990, the electricity generation, supply and distribution industries
in Great Britain have been privatized, and competition has been introduced in
generation and supply. Electricity is produced by generators, transmitted
through the national grid transmission system by The National Grid Company plc
(or in Scotland by Scottish Power or Scottish Hydro Electric) and distributed to
customers by the fourteen Distribution License Holders, which we refer to as
DLHs, in their respective distribution service areas. During the fourth quarter
of 1998, the market for supplying electricity began to be opened to competition
through a phased-in program. This program, which proceeded by geographic areas,
was completed in 1999.

Under the Utilities Act 2000, the public electricity supply license created
pursuant to the Electricity Act 1989 was replaced by two separate licenses--the
electricity distribution license and the electricity supply license. When the
relevant provision of the Utilities Act 2000 became effective on October 1,
2001, the public electricity supply licenses formerly held by Northern Electric
plc and Yorkshire Electricity Group plc were split so that separate subsidiaries
held licenses for electricity distribution and electricity supply. In order to
comply with the Utilities Act 2000 and to facilitate this license splitting,
Northern Electric plc and Yorkshire Electricity Group plc (and each of the other
holders of the former public

electricity supply licenses) each made a statutory transfer scheme that was
approved by the Secretary of State for Trade and Industry. These schemes
provided for the transfer of certain assets and liabilities to the licensed
subsidiaries. This occurred on October 1, 2001, a date set by the Secretary of
State for Trade and Industry. As a consequence of these schemes, the electricity
distribution businesses of Northern Electric plc and Yorkshire Electricity Group
plc were transferred to NED and YED, respectively. NED and YED are each holders
of an electricity distribution license. The residual elements of the Electricity
Supply licenses were transferred to Innogy in connection with the sale of
Northern Electric's electricity and gas supply business to Innogy and the
retention by Innogy of the electricity and gas supply business of Yorkshire
Electricity, all as a part of the Northern Electric/Yorkshire Electricity Swap
on September 21, 2001.

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

Most revenue of the DLHs is controlled by a distribution price control
formula which is set out in the license of each DLH. It has been the practice of
Ofgem (and its predecessor body, the Office of Electricity Regulation), to
review the formula periodically and to reset it at intervals of five year
duration. The formula may be varied with the consent of the DLH, or if the DLH
does not consent, following a review by the U.K.'s competition authority.

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

o the actual operating costs of each of the licensees;

o the operating costs which each of the licensees would incur if it were
as efficient as, in Ofgem's judgment, the most efficient licensee;

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

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

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

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

As a result of the most recent review, the allowed revenue of Northern
Electric's distribution business was reduced by 24%, in real terms, and the
allowed revenue of Yorkshire Electricity's distribution business was reduced by
23%, in real terms, with effect from April 1, 2000. The range of reductions for
all licensees in Great Britain was between 4% and 33%.

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

The distribution prices allowable under the current distribution price
control formula are expected to be reviewed by Ofgem in time for a revised
formula to take effect from April 1, 2005. The formula may be further reviewed
at other times in the discretion of the regulator. Ofgem has recently modified
the licenses of all DLHs to implement an "Information and Incentives Project"
under which up to 2% of a DLH's regulated income depends upon the performance of
the DLH's distribution system as measured by the number and duration of customer
interruptions and upon the level of customer satisfaction monitored by Ofgem.

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

CALENERGY GENERATION--DOMESTIC

Each of the operating domestic power facilities owned through CE Gen meets
the requirements promulgated under PURPA to be qualifying facilities, except for
Cordova Energy. Qualifying facility or "QF" status under PURPA provides two
primary benefits. First, regulations under PURPA exempt QFs from PUHCA, the FERC
rate regulation under the Federal Power Act and the state laws concerning rates
of electric utilities and financial and organization regulations of electric
utilities. Second, the FERC's regulations promulgated under PURPA require that
(1) electric utilities purchase electricity generated by QFs, the construction
of which commenced on or after November 9, 1978, at a price based on the
purchasing utility's Avoided Cost of Energy, (2) electric utilities sell
back-up, interruptible, maintenance and supplemental power to QFs on a
non-discriminatory basis, and (3) electric utilities interconnect with QFs in
their service territories. There can be no assurance that the QF status of such
CalEnergy Generation--Domestic facilities will be maintained.

CORDOVA ENERGY

Cordova Energy is exempt from regulation under PUHCA because it is an
exempt wholesale generator. PUHCA provides that an exempt wholesale generator is
not considered to be an electric utility company. An exempt wholesale generator
is permitted to sell capacity and electricity in the wholesale markets, but not
in the retail markets.

If an exempt wholesale generator is subject to a "material change" in facts
that might affect its continued eligibility for exempt wholesale generator
status, within 60 days of such material change, the exempt wholesale generator
must (1) file a written explanation of why the material change does not affect
its exempt wholesale generator status, (2) file a new application for exempt
wholesale generator status, or (3) notify the FERC that it no longer wishes to
maintain exempt wholesale generator status.

CALENERGY GENERATION--FOREIGN

The Philippine Congress has passed the Electric Power Industry Reform Act
of 2001, which is aimed at restructuring the Philippine power industry,
privatization of the NPC and introduction of a competitive electricity market,
among other initiatives. The implementation of the bill may have an adverse
impact on the Company's future operations in the Philippines and the Philippines
power industry as a whole, the effect of which is not yet determinable and
estimable.

obligations, rights and remedies thereunder, such disputes will be determined
by international arbitration in a neutral forum conducted in accordance with
the rules of the International Chamber of Commerce or UNCITRAL, as applicable.

Representatives of CE Casecnan, together with certain current and former
Philippine government officials, also have been requested to appear, and have
appeared, before a Philippine Senate committee which has independently raised
questions and made allegations with respect to the Casecnan Project's tariff
structure and implementation. No further hearings are scheduled at this time.

HOMESERVICES

The Department of Housing and Urban Development and the Federal Home
Administration, or FHA, lender guidelines prohibit the collection of a
broker-fee from FHA financed buyers where the FHA lender is affiliated with the
real estate broker or where there is no buyer-broker agreement. The majority of
HomeServices' subsidiaries have been charging a broker fee to their buyers and
sellers, except in circumstances where the FHA guidelines prohibit it.
Nonetheless, HomeServices is working with the FHA to change the lenders'
guidelines to permit collection of these fees.

PIPELINE SAFETY REGULATION

Our pipeline operations are subject to regulation by the United States
Department of Transportation under the Natural Gas Pipeline Safety Act of 1969,
as amended, relating to design, installation, testing, construction, operation
and management of our pipeline system. The Natural Gas Pipeline Safety Act
requires any entity that owns or operates pipeline facilities to comply with
applicable safety standards, to establish and maintain inspection and
maintenance plans and to comply with such plans. We conduct internal audits of
our facilities every four years, with more frequent reviews of those we deem
higher risk. The United States Department of Transportation routinely audits our
pipeline. Compliance issues that arise during these audits or during the normal
course of business are addressed on a timely basis.

The aging pipeline infrastructure in the United States has led to
heightened regulatory and legislative scrutiny of pipeline safety and integrity
practices. The Natural Gas Pipeline Safety Act was amended by the Pipeline
Safety Act of 1992 to require the Department of Transportation's Office of
Pipeline Safety to consider protection of the environment when developing
minimum pipeline safety regulations. In addition, the amendments require that
the Department of Transportation issue pipeline regulations concerning, among
other things, the circumstances under which emergency flow restriction devices
should be required, training and qualification standards for personnel involved
in maintenance and operation, and requirements for periodic integrity
inspections, as well as periodic inspection of facilities in navigable waters
which could pose a hazard to navigation or public safety. In addition, the
amendments narrowed the scope of our gas pipeline exemption pertaining to
underground storage tanks under the Resource Conservation and Recovery Act.
While the effect of new legislation, which has been passed by Congress but not
yet signed by the President, on us is still being determined, we expect to spend
the capital or make the operational changes necessary to comply with all
pipeline integrity legislation. Northern Natural Gas and Kern River currently
project that they will make significant expenditures to meet these new
regulations.

We believe our subsidiaries' pipeline operations comply in all material
respects with the Natural Gas Pipeline Safety Act, but the industry, including
our subsidiaries, could be required to incur additional capital expenditures and
increased costs depending upon final regulations issued by the Department of
Transportation under the Natural Gas Pipeline Safety Act.

ENVIRONMENTAL REGULATION

DOMESTIC

We are subject to a number of federal, state and local environmental laws
and health and other regulations affecting many aspects of our present and
future operations in the United States. Such laws and regulations generally
require us to obtain and comply with a wide variety of licenses, permits and

other approvals. No assurance can be given that in the future all necessary
permits and approvals will be obtained or renewed and all applicable statutes
and regulations complied with. In addition, regulatory compliance for the
construction of new power facilities and gas pipeline operations is a costly and
time-consuming process, and intricate and rapidly changing environmental
regulations may require major expenditures for permitting or other compliance
issues and may create the risk of expensive delays or material impairment of
project value if projects cannot function as planned due to changing regulatory
requirements or local opposition. We believe that our operating power facilities
and gas pipeline operations are currently in material compliance with all
applicable federal, state and local laws and regulations. However, we cannot
assure you that existing regulations will not be revised or that new regulations
will not be adopted or become applicable to us which could have an adverse
impact on our operating costs and operations.

In accordance with the requirements of Section 112 of the Clean Air Act
Amendments of 1990, the EPA has performed a study of the hazards to public
health reasonably anticipated to occur as a result of emissions of hazardous air
pollutants by electric utility steam generating units. In December 2000, after
research and monitoring of mercury emissions, the EPA concluded that it is
appropriate and necessary to regulate mercury emissions from coal-fired
generating units. It is anticipated that rules will be developed to regulate
these emissions in 2003 or 2004 with reductions of mercury emissions effective
in 2007. The cost to MidAmerican Energy of reducing its mercury emissions would
depend on available technology at the time, but could be material.

In July 1997, the EPA adopted revisions to the National Ambient Air Quality
Standards for ozone and a new standard for fine particulate matter. Based on
data to be obtained from monitors located throughout each state, the EPA will
determine which states have areas that do not meet the air quality standards
(i.e., areas that are classified as nonattainment). The standards were subjected
to legal proceedings, and in February 2001, United States Supreme Court upheld
the constitutionality of the standards, though remanding the issue of
implementation of the ozone standard to the EPA. As a result of a decision
rendered by the United States Circuit Court of Appeals for the District of
Columbia, the EPA is moving forward in implementation of the ozone and fine
particulate standards and is analyzing existing monitoring data to determine
attainment status.

The impact of the new standards on us is currently unknown. MidAmerican
Energy's generating stations may be subject to emission reductions if the
stations are located in nonattainment areas or contribute to nonattainment areas
in other states. As part of state implementation plans to achieve attainment of
the standards, MidAmerican Energy could be required to install control equipment
on its generating stations or decrease the number of hours during which these
stations operate.

The ozone and fine particulate matter standards could also, in whole or in
part, be superceded by one of a number of multi-pollutant emission reduction
proposals currently under consideration at the federal level. In July 2002,
legislation was introduced in Congress to implement the Administration's "Clear
Skies Initiative," calling for the reduction in emissions of sulfur dioxide,
nitrogen oxides and mercury through a cap-and-trade system. Reductions would
begin in 2008 with additional emission reductions being phased in through 2018.
While legislative action is necessary for this or other multi-pollutant emission
reduction initiatives to become effective, MidAmerican Energy has implemented a
planning process that forecasts the site-specific controls and actions required
to meet emissions reductions of this nature.

Since the adoption of the United Nations Framework on Climate Change in
1992, there has been a worldwide effort to reduce greenhouse gas, or GHG,
emissions to 1990 levels or below. In December 1997, the U.S. participated in
the Kyoto, Japan negotiations, where the basis of a Climate Change treaty was
formulated. Under the treaty, known as the Kyoto Protocols, the United States
would have an overall reduction target of 7% in GHG emissions from 1990 levels
by 2008-2012. To date, the Senate has not ratified the Kyoto Protocols. In
addition, President Bush has recently indicated his opposition to the Kyoto
Protocols. However, given the widespread international and public support for
the reduction of GHG emissions, it is not unlikely that GHG reduction
regulations will come to pass, even if not related to the Kyoto Protocols. At
this time, we cannot estimate the potential impact of such regulations on us or
our subsidiaries.

In 2001, the state of Iowa passed legislation that, in part, requires
rate-regulated utilities to develop a multi-year plan and budget for managing
regulated emissions from their generating facilities in a cost-effective
manner. MidAmerican Energy's proposed plan and associated budget was filed with
the IUB on April 1, 2002, in accordance with state law. MidAmerican Energy
expects the IUB to rule on the prudence of such plan during the first or second
quarter of 2003. MidAmerican Energy is required to file updates to such plan at
least every two years.

MidAmerican Energy's proposed plan provides its projected air emission
reductions considering current proposals being debated at the federal level and
describes a coordinated long-range plan to achieve these air emission
reductions. MidAmerican Energy's proposed plan also provides specific actions to
be taken at each coal-fired generating facility and related costs and timing for
each action.

MidAmerican Energy's proposed plan outlines $732.0 million in environmental
investments to existing coal-fired generating units, some of which are jointly
owned, over a nine-year period from 2002 through 2010. MidAmerican Energy's
share of these investments is $546.6 million, $67.9 million of which is
projected to be incurred during the 2002-2005 rate freeze period. Such plan also
identifies expenses that will be incurred at the generating facilities to
operate and maintain the environmental equipment installed as a result of such
plan.

Following the expiration on December 31, 2005 of the rate settlement
agreement which was approved by the IUB on December 21, 2001, MidAmerican
Energy's proposed plan suggests the use of an adjustment mechanism for recovery
of such plan's costs, similar to the tracking mechanisms for cost recovery of
renewable energy and energy efficiency expenditures that are presently part of
MidAmerican Energy's regulated electric rates. See "Regulation--MidAmerican
Energy" for a discussion of the settlement agreement.

Federal, state and local environmental laws and regulations currently have,
and future modifications may have, the effect of increasing the lead time for
the construction of new facilities, significantly increasing the total cost of
new facilities, requiring modification of our existing facilities, increasing
the risk of delay on construction projects, increasing our cost of waste
disposal and possibly reducing the reliability of service we provide and the
amount of energy available from our facilities. Any of such items could have a
substantial impact on amounts required to be expended by us in the future.

Under various federal, state and local environmental laws and regulations,
a current or previous owner or operator of any facility, including an electric
generating facility, may be required to investigate and remediate past releases
or threatened releases of hazardous or toxic substances or petroleum products
located at the facility, and may be held liable to a governmental entity or to
third parties for property damage, personal injury and investigation and
remediation costs incurred by a party in connection with any releases or
threatened releases. These laws, including the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended by the Superfund
Amendments and Reauthorization Act of 1986, impose liability without regard to
whether the owner knew of or caused the presence of the hazardous substances,
and courts have interpreted liability under such laws to be strict and joint and
several. The cost of investigation, remediation or removal of substances may be
substantial. In connection with the ownership and operation of facilities, we
and our subsidiaries may be liable for such costs. Even at those sites where we
are not presently aware of any contamination that currently requires
remediation, given the use of hazardous substances at each facility and their
locations, often within areas that have a long history of industrial use, it is
possible that we will discover currently unknown contamination or that future
spills or other causes of contamination will occur. As a result, it is possible
that we may become liable for remediation.

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

is to determine whether waste materials are present, whether the materials
constitute an environmental or health risk, and whether MidAmerican Energy has
any responsibility for remedial action. Investigations of the sites are at
various stages, and MidAmerican Energy has conducted ten removal actions to
date and is continuing to evaluate several of the sites to determine the
appropriate site remedies, if any, necessary to obtain site closure from the
agencies.

MidAmerican Energy estimates the range of possible costs for investigation,
remediation and monitoring for the sites discussed above to be $16 million to
$30 million. MidAmerican Energy's estimate of the probable cost for these sites
as of September 30, 2002 was $18 million. The estimate consists of $1 million
for investigation costs, $6 million for remediation costs, $9 million for ground
water treatment and monitoring costs and $2 million for closure and
administrative costs. This estimate has been recorded as a liability and a
regulatory asset for future recovery. MidAmerican Energy projects that these
amounts will be paid or incurred over the next five years.

Accruals for probable remediation costs are established based on
site-specific estimates and are evaluated and revised quarterly as appropriate
based on additional information obtained during investigation and remedial
activities. The estimated recorded liability could change materially based on
facts and circumstances derived from site investigations, changes in required
remedial action and changes in technology relating to remedial alternatives.
Insurance recoveries have been received for some of the sites under
investigation. Those recoveries are intended to be used principally for
accelerated remediation, as specified by the IUB, and are recorded as a
regulatory liability. Additionally, as viable potentially responsible parties
are identified, those parties are evaluated for potential contributions, and
cost recovery is pursued when appropriate.

Although the timing of potential incurred costs and recovery of costs in
MidAmerican Energy's rates may affect the results of operations in individual
periods, management believes that the outcome of issues related to the
remediation of former manufactured gas plant facilities will not have a material
adverse effect on our financial position, results of operations or cash flows.

UNITED KINGDOM

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

The United Kingdom government introduced new contaminated land legislation
in April 2000 that requires companies to:

o put in place a program for investigating the company's history to
identify problem sites for which it is responsible;

o make a clear commitment to meeting responsibilities for cleaning up
those sites;

o provide funding to make sure that this can happen; and

o make commitments public.

CE Electric UK is in the process of completing the evaluation work on the
three sites that may be subject to the legislation. Exploratory work with an
environmental remediation company is in progress on these sites.

The Environmental Protection Act (Disposal of PCB's and other Dangerous
Substances) Regulations 2001 were introduced on May 5, 2000. The regulations
required that transformers containing over 50 parts per million of PCB's and
other dangerous substances be registered with the Environment Agency by July 31,
2000. Transformers containing 500 parts per million had to be de-contaminated by
December 31, 2000. CE Electric UK has registered 380 items above 50 parts per
million, decontaminated 120 items and informed the Environment Agency that it is
continuing with its sampling, labeling and registration program. These
regulations are not expected to have a material impact on us.

The Groundwater Regulations seek to prevent listed hazardous substances
from entering groundwater and strengthens the United Kingdom Environment
Agency's powers to require additional

protective measures, especially in areas of important groundwater supplies.
Mineral oils and hydrocarbons are included in the list of more tightly
controlled substances, or List I substances. This affects the high voltage
fluid filled electricity cable network incorporating an insulating fluid that
is currently in List I. The existing voluntary Operating Code of Practice, as
agreed between the Agency and the Electricity Supply Industries, is undergoing
revision through the services of the Electricity Association to address the
regulatory changes. The existing voluntary Operating Code of Practice is, and
any revised Operating Code of Practice will be, incorporated into the operating
practices of NED and YED. Any revisions which are made are not expected to have
a material impact on us.

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

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

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

Environmental laws and regulations in the United Kingdom currently have,
and future modifications may have, the effect of requiring modification of CE
Electric UK's facilities, increasing its cost of waste disposal and possibly
reducing the reliability of service it provides and the amount of energy
available from its facilities. Any of such items could have a substantial impact
on amounts required to be expended by CE Electric UK in the future.

PHILIPPINES

On June 23, 1999, the Philippine Congress enacted the Philippine Clean Air
Act of 1999. The related implementing rules and regulations were adopted in
November 2000. The law as written would require the Upper Mahiao, Mahanagdong
and Malitbog projects, which we collectively refer to as the Leyte Projects, to
comply with a maximum discharge of 200 grams of hydrogen sulfide per gross
megawatt hour of output by June 2004. On November 13, 2002, the Secretary of the
Philippine Department of Environmental and Natural Resources issued Memorandum
Circular, or MC, 2002-13 designating geothermal areas as "special airsheds."
PNOC-EDC has advised us that the MC exempts the Upper Mahiao, Mahanagdong and
Malitbog plants from the need to comply with the point-source emission standards
of the Clean Air Act. The Leyte Projects intend to seek confirmation of the
impact of the MC from PNOC-EDC and from the Philippine Department of
Environmental and Natural Resources.

NUCLEAR REGULATION

Each licensee of a nuclear facility is required to provide financial
assurance for the cost of decommissioning its licensed nuclear facility. In
general, decommissioning of a nuclear facility means the obligation to safely
remove the facility from service and restore the property to a condition
allowing unrestricted use by the operator.

Based on information presently available, we expect to contribute
approximately $41 million during the period 2002 through 2006 to an external
trust established for the investment of funds for decommissioning the Quad
Cities station. Approximately 55% of the fair value of the trust's funds are now
invested in domestic corporate debt and common equity securities. The remainder
is invested in investment grade municipal and United States Treasury bonds. The
Quad Cities station decommissioning costs properly charged to Iowa customers are
included in base rates, and recovery of any increases in those amounts must be
sought through the normal ratemaking process.

As a result of a July 31, 2002 Settlement Agreement and Release relating to
a restructuring of the power purchase contract between MidAmerican Energy and
NPPD, MidAmerican Energy will no longer be accruing for decommissioning costs
for the Cooper Nuclear Station. Refer to note 12H of our notes to consolidated
financial statements for the nine months ended September 30, 2002 contained in
this prospectus for a discussion of the settlement and contract restructuring.

MidAmerican Energy maintains financial protection against catastrophic
loss associated with its interest in the Quad Cities station through a
combination of insurance purchased by Exelon Generation Company, LLC (the
operator and joint owner of the Quad Cities station), insurance purchased
directly by MidAmerican Energy and the mandatory industry-wide loss funding
mechanism afforded under the Price-Anderson Amendments Act of 1988. The general
types of coverage are: nuclear liability, property coverage and nuclear worker
liability.

Exelon Generation purchased nuclear liability insurance for the Quad Cities
station in the maximum available amount of $200 million. In accordance with the
Price-Anderson Amendments Act of 1988, excess liability protection above that
amount is provided by a mandatory industry-wide Secondary Financial Protection
program under which the licensees of nuclear generating facilities could be
assessed for liability incurred due to a serious nuclear incident at any
commercial nuclear reactor in the United States. Currently, MidAmerican Energy's
aggregate maximum potential share of an assessment for the Quad Cities station
is approximately $44 million per incident, payable in installments not to exceed
$5 million annually.

The property insurance covers property damage, stabilization and
decontamination of the facility, disposal of the decontaminated material and
premature decommissioning arising out of a covered loss. For the Quad Cities
station, Exelon Generation purchased primary and excess property insurance
protection for the combined interests in the Quad Cities station, with coverage
limits totaling $2.1 billion. MidAmerican Energy also directly purchased extra
expense/business interruption coverage for its share of replacement power and/or
other extra expenses in the event of a covered accidental outage at the Quad
Cities station. The property and related coverages purchased directly by
MidAmerican Energy and by Exelon Generation, which includes the interests of
MidAmerican Energy, are underwritten by an industry mutual insurance company and
contain provisions for retrospective premium assessments should two or more full
policy-limit losses occur in one policy year. Currently, the maximum aggregate
retrospective amounts that could be assessed against MidAmerican Energy from
industry mutual policies for its obligations associated with the Quad Cities
station total $6.3 million.

The master nuclear worker liability coverage, which was purchased by Exelon
Generation for the Quad Cities station, is an industry-wide guaranteed-cost
policy with an aggregate limit of $200 million for the nuclear industry as a
whole, which is in effect to cover worker tort claims in nuclear-related
industries.

LEGAL PROCEEDINGS

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

CASECNAN CONSTRUCTION ARBITRATION

On February 12, 2001, the contractor for the Casecnan Project, a
consortioum consisting of Cooperativa Muratori Cementisti CMC di Ravenna and
Impresa Pizzarotti & C. Spa., working together with Siemens A.G. and Sulzer
Hydro Ltd., which we collectively refer to as the Contractor, filed a Request
for Arbitration with the International Chamber of Commerce seeking an extension
of the Guaranteed Substantial Completion Date by up to 153 days through August
31, 2001 resulting from various alleged force majeure events. In its March 20,
2001 Supplement to Request for Arbitration, the Contractor requested
compensation for alleged additional costs of approximately $4 million it
incurred from the claimed force majeure events to the extent it is unable to
recover from its insurer. On April 20, 2001, the Contractor filed a further
supplement seeking an additional compensation for damages of approximately $62
million for the alleged force majeure event (and geologic conditions) related to
the collapse of the surge shaft. The Contractor also has alleged that the
circumstances surrounding the placing of the Casecnan Project into commercial
operation on December 11, 2001 amounted to a repudiation of the Construction
Contract and has filed a claim for unspecified quantum meruit damages. CE
Casecnan believes all such allegations and claims are without merit and is
vigorously contesting the Contractor's claims. The arbitration is being
conducted applying New York law and in accordance with the rules of the
International Chamber of Commerce.

Hearings have been held in connection with this arbitration in July 2001,
September 2001, January 2002 and March 2002. As part of those hearings, on June
25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from making
calls on the demand guaranty posted by Banca di Roma in support of the
Contractor's obligations to CE Casecnan for delay liquidated damages. As a
result of the continuing nature of that injunction, on April 26, 2002, CE
Casecnan and the Contractor mutually agreed that no demands would be made on the
Banca di Roma demand guaranty except pursuant to an arbitration award. As of
September 30, 2002, however, CE Casecnan has received approximately $6.0 million
of liquidated damages from demands made on the demand guarantees posted by
Commerzbank on behalf of the Contractor. In November 2002, hearings were held on
the Contractor's claim with respect to the alleged unenforceability of the delay
liquidated damages clause. On November 7, 2002, the International Chamber of
Commerce issued the arbitration tribunal's partial award with respect to the
Contractor's force majeure and geologic conditions claims. The arbitration panel
awarded the Contractor 18 days of schedule relief in the aggregate for all of
the force majeure events and awarded the Contractor $3.8 million with respect to
the cost of the collapsed surge shaft. All of the Contractor's other claims that
were heard by the arbitration tribunal were denied.

Further hearings on the Contractor's repudiation and quantum meruit claims
and certain other matters are scheduled for January 2003. These claims, and the
alleged unenforceability of the delay liquidated damages clause, have not been
ruled on by the arbitration tribunal.

CASECNAN SHAREHOLDER LITIGATION

Pursuant to the share ownership adjustment mechanism in the CE Casecnan
shareholder agreement, which is based upon pro forma financial projections of
the Casecnan Project prepared following commencement of commercial operations,
in February 2002, CE Casecnan, through its indirect wholly owned subsidiary CE
Casecnan Ltd., advised the minority shareholder LaPrairie Group Contractors
(International) Ltd., or LPG, that our indirect ownership interest in CE
Casecnan had increased to 100% effective from commencement of commercial
operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the
State of California, City and County of San Francisco against, inter alia, CE
Casecnan Ltd. and us. In the complaint, LPG seeks compensatory and punitive
damages for alleged breaches of the shareholder agreement and alleged breaches
of fiduciary duties allegedly owed by CE Casecnan Ltd. and us to LPG. The
complaint also seeks injunctive relief against all defendants and a declaratory
judgment that LPG is entitled to maintain its 15% interest in CE Casecnan. The
impact, if any, of this litigation on us cannot be determined at this time.

CASECNAN NIA ARBITRATION

Under the terms of an agreement between CE Casecnan and NIA regarding the
Casecnan Project, NIA has the option of timely reimbursing CE Casecnan directly
for certain taxes CE Casecnan has paid. If NIA does not so reimburse CE
Casecnan, the taxes paid by CE Casecnan result in an increase in the Water
Delivery Fee under the Casecnan Project agreement. The payment of certain other
taxes by CE Casecnan results automatically in an increase in the Water Delivery
Fee. As of September 30, 2002, CE Casecnan has paid approximately $54.4 million
in taxes which as a result of the foregoing provisions had resulted in an
increase in the Water Delivery Fee. NIA has failed to pay the portion of the
Water Delivery Fee each month which relates to the payment of these taxes by CE
Casecnan. As a result of this non-payment, on August 19, 2002, CE Casecnan filed
a Request for Arbitration against NIA, seeking payment of such portion of the
Water Delivery Fee and enforcement of the relevant provision of the Casecnan
Project agreement going forward. The arbitration will be conducted in accordance
with the rules of the International Chamber of Commerce.

MALITBOG ARBITRATION

On October 16, 2000, VGPC commenced arbitration against PNOC-EDC by serving
it with a Notice of Arbitration and Statement of Claim alleging that PNOC-EDC
breached the Malitbog energy conversion agreement by improperly characterizing
certain No Fault Outages as Forced Outage Hours and then deducting them from the
total number of hours each month for purposes of determining payments due to
VGPC. On December 22, 2000, VGPC filed an Amended Statement of Claim pursuant to
which VGPC added a claim that PNOC-EDC breached the Malitbog agreement by
refusing to accept VGPC's specified Nominated Capacity for contract years July
25, 1999 to July 25, 2000, and July 25, 2000 to July 25, 2001. A Second Amended
Statement of Claim was filed on March 9, 2001 to add an issue related to the
proper duration of annual scheduled maintenance on the Malitbog plant. VGPC
intends to vigorously pursue its claims in this proceeding. Hearings were
conducted from June 24, 2002 to July 5, 2002 in Sydney, Australia. On November
27, 2002, the arbitration panel issued a unanimous award which states that
PNOC-EDC is obligated to pay for all the hours that VGPC spent on Scheduled
Maintenance in the year 2000 to the extent that the total number of days of
Scheduled Outage has not exceeded 45 days. The award also orders PNOC-EDC to
accept VGPC's Nominated Capacity for project years through 2002 and to pay all
amounts owed to VGPC in this regard. Furthermore, the award declares that VGPC
can only declare no fault outages if VGPC is not at fault, but places the burden
of proof in this regard on PNOC-EDC. Also, the award orders VGPC to pay PNOC-EDC
$1.6 million in costs. The award orders VGPC and PNOC-EDC to work together to
attempt to agree on the amounts owed under the terms of the order and if the
parties cannot reach an agreement, each party is to make submissions to the
arbitration panel by the middle of January 2003.

MAHANAGDONG ARBITRATION

On September 25, 2002, CE Luzon commenced arbitration against PNOC-EDC
alleging that PNOC-EDC breached the Mahanagdong energy conversion agreement by
refusing to accept CE Luzon's Nominated Capacity for contract years July 25,
2001 to July 25, 2002 and July 25, 2002 to July 25, 2003. CE Luzon intends to
vigorously pursue its claim in this proceeding. The arbitration will be
conducted in accordance with the rules of the International Chamber of Commerce.

PIPELINE LITIGATION

declined to intervene in any of the Grynberg qui tam cases, including the
actions filed against Kern River and Northern Natural Gas in the United States
District Court for the District of Colorado. On October 21, 1999, the Panel on
Multi-District Litigation transferred the Grynberg qui tam cases, including the
ones filed against Kern River and Northern Natural Gas, to the United States
District Court for the District of Wyoming for pre-trial purposes. Motions to
dismiss the complaint, filed by various defendants including Northern Natural
Gas and Williams, which was the former owner of Kern River, were denied on May
18, 2001. In connection with the purchase of Kern River from Williams in March
2002, Williams agreed to indemnify us against any liability for this claim;
however, no assurance can be given as to the ability of Williams to perform on
this indemnity should it become necessary. No such indemnification was obtained
in connection with the purchase of Northern Natural Gas in August 2002. We
believe that the Grynberg cases filed against Kern River and Northern Natural
Gas are without merit and Williams, on behalf of Kern River pursuant to its
agreement to indemnify us, and Northern Natural Gas, intends to defend these
actions vigorously.

On June 8, 2001, a number of interstate pipeline companies, including Kern
River and Northern Natural Gas, were named as defendants in a nationwide class
action lawsuit which had been pending in the 26th Judicial District, District
Court, Stevens County Kansas, Civil Department against other defendants,
generally pipeline and gathering companies, since May 20, 1999. The plaintiffs
allege that the defendants have engaged in mismeasurement techniques that
distort the heating content of natural gas, resulting in an alleged underpayment
of royalties to the class of producer plaintiffs. In November 2001, Kern River
and Northern Natural Gas, along with the coordinating defendants, filed a motion
to dismiss under Rules 9B and 12B of the Kansas Rules of Civil Procedure. In
January 2002, Kern River and most of the coordinating defendants filed a motion
to dismiss for lack of personal jurisdiction. The court has yet to rule on these
motions. The plaintiffs filed for certification of the plaintiff class on
September 16, 2002. Williams has agreed to indemnify us against any liability
associated with Kern River for this claim; however, no assurance can be given as
to the ability of Williams to perform on this indemnity should it become
necessary. Williams, on behalf of Kern River and other entities, anticipates
joining with Northern Natural Gas and other defendants in contesting
certification of the plaintiff class. Kern River and Northern Natural Gas
believe that this claim is without merit and that Kern River's and Northern
Natural Gas' gas measurement techniques have been in accordance with industry
standards and its tariff.

MANAGEMENT

OUR DIRECTORS AND EXECUTIVE OFFICERS

Our current executive officers and directors and their positions are as
follows:

NAME POSITION
- ------------------------ ------------------------------------------------------------

David L. Sokol Chairman of the Board, Chief Executive Officer and Director

Gregory E. Abel President, Chief Operating Officer and Director

Patrick J. Goodman Senior Vice President and Chief Financial Officer

Douglas L. Anderson Senior Vice President and General Counsel

Keith D. Hartje Senior Vice President and Chief Administrative Officer

Warren E. Buffett Director

Walter Scott, Jr. Director

Marc D. Hamburg Director

W. David Scott Director

Edgar D. Aronson Director

John K. Boyer Director

Stanley J. Bright Director

Richard R. Jaros Director

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

Set forth below is certain information with respect to each of the
foregoing executive officers and directors:

DAVID L. SOKOL, 46, Chairman of the Board of Directors and Chief Executive
Officer. Mr. Sokol has been CEO since April 19, 1993 and served as President of
MEHC from April 19, 1993 until January 21, 1995. Mr. Sokol has been Chairman of
the Board of Directors since May 1994 and a director since March 1991. Formerly,
among other positions held in the independent power industry, Mr. Sokol served
as President and Chief Executive Officer of Kiewit Energy Company, which at that
time was a wholly owned subsidiary of Peter Kiewit Sons', Inc.

GREGORY E. ABEL, 40, President, Chief Operating Officer and Director. Mr.
Abel joined us in 1992 and initially served as Vice President and Controller.
Mr. Abel is a Chartered Accountant and, from 1984 to 1992, he was employed by
Price Waterhouse. As a Manager in the San Francisco office of Price Waterhouse,
he was responsible for clients in the energy industry.

PATRICK J. GOODMAN, 36, Senior Vice President and Chief Financial Officer.
Mr. Goodman joined us in 1995, and previously served in various accounting
positions including Senior Vice President and Chief Accounting Officer. Prior to
joining us, Mr. Goodman was a financial manager for National Indemnity Company
and a senior associate at Coopers & Lybrand.

DOUGLAS L. ANDERSON, 44, Senior Vice President and General Counsel. Mr.
Anderson joined us in February 1993 and has served in various legal positions
including General Counsel of our independent power affiliates. From 1990 to
1993, Mr. Anderson was a corporate attorney with Fraser, Stryker, Meusey, Olson,
Boyer & Bloch, P.C., a law firm in Omaha, Nebraska. Prior to that Mr. Anderson
was a principal in the firm of Anderson and Anderson.

KEITH D. HARTJE, 52, Senior Vice President and Chief Administrative
Officer. Mr. Hartje has been with MidAmerican Energy and its predecessor
companies since 1973. In that time, he has held a number of positions, including
General Counsel and Corporate Secretary, District Vice President for southwest
Iowa operations, and Vice President, Corporate Communications.

WARREN E. BUFFETT, 72, Director. Mr. Buffett has been one of our directors
since March 2000. He is Chairman of the Board and Chief Executive Officer of
Berkshire Hathaway. Mr. Buffett is a Director of the Coca-Cola Company, the
Gillette Company and The Washington Post Company.

WALTER SCOTT, JR., 71, Director. Mr. Scott has been one of our directors
since June 1991. Mr. Scott was our Chairman and Chief Executive Officer from
January 8, 1992 until April 19, 1993. For more than the past five years, he has
been Chairman of the Board of Directors of Level 3 Communications, Inc., a
successor to certain businesses of Peter Kiewit Sons', Inc. Mr. Scott is a
director of Peter Kiewit Sons', Inc., Berkshire Hathaway, Burlington Resources,
Inc., ConAgra, Inc., Valmont Industries, Inc., Kiewit Materials Co.,
Commonwealth Telephone Enterprises, Inc. and RCN Corporation. Mr. Walter Scott,
Jr. is the father of Mr. W. David Scott.

MARC D. HAMBURG, 53, Director. Mr. Hamburg has been one of our directors
since March 2000. He has served as Vice President--Chief Financial Officer of
Berkshire Hathaway since October 1, 1992 and Treasurer since June 1, 1987, his
date of employment with Berkshire Hathaway.

W. DAVID SCOTT, 41, Director. Mr. Scott has been one of our directors
since March 2000. Mr. Scott formed Magnum Resources, Inc., a commercial real
estate investment and management company, in October 1994, and has served as
its President and Chief Executive Officer since its inception. Before forming
Magnum Resources, Mr. Scott worked for America First Companies, Cornerstone
Banking Group and Peter Kiewit Sons', Inc. Mr. Scott has been a director of
America First Mortgage Investments, Inc., a mortgage REIT, since 1998. Mr. W.
David Scott is the son of Mr. Walter Scott, Jr.

EDGAR D. ARONSON, 68, Director. Mr. Aronson has been one of our directors
since 1983. Mr. Aronson founded EDACO, Inc., a private venture capital company,
in 1981 and has been President of EDACO, Inc. since that time. Prior to that,
Mr. Aronson was Chairman of Dillon, Read International from 1979 to 1981 and a
General Partner in charge of the International Department of Salomon Brothers
Inc. from 1973 to 1979. Mr. Aronson served during 1962-1968 as Vice President
consecutively in the International Departments of First National Bank of
Chicago and Republic National Bank of New York. He founded the International
Department of Salomon Brothers and Hutzler in 1968.

JOHN K. BOYER, 58, Director. Mr. Boyer has been one of our directors since
March 2000. From 1993 to date, he has been a partner with Fraser, Stryker,
Meusey, Olson, Boyer & Bloch, P.C., a law firm with emphasis on corporate,
commercial, federal, state and local taxation law.

STANLEY J. BRIGHT, 62, Director. Mr. Bright is our Vice Chairman and was
Chairman and Chief Executive Officer of MidAmerican Energy from July 1, 1995
until March 1999. Mr. Bright joined Iowa-Illinois Gas and Electric Company (a
predecessor of MidAmerican Energy) as Vice President and Chief Financial
Officer in 1986, became a director in 1987, President and Chief Operating
Officer in 1990, and Chairman and Chief Executive Officer in 1991.

RICHARD R. JAROS, 50, Director. Mr. Jaros has been one of our directors
since March 1991. Mr. Jaros served as our President and Chief Operating Officer
from January 8, 1992 to April 19, 1993 and as Chairman of the Board from April
19, 1993 to May 1994. Until July 1997, Mr. Jaros was Executive Vice President
and Chief Financial Officer of Peter Kiewit Sons', Inc. and President of Kiewit
Diversified Group, Inc., which is now Level 3 Communications, Inc. From 1990
until January 8, 1992, Mr. Jaros served as a Vice President of Peter Kiewit
Sons', Inc. Mr. Jaros serves as director of Commonwealth Telephone Enterprises,
Inc., RCN Corporation and Level 3 Communications, Inc.

EXECUTIVE COMPENSATION

The following table sets forth the compensation of our Chief Executive
Officer and our four other most highly compensated executive officers who were
employed as of December 31, 2001, which we refer to as our Named Executive
Officers. Information is provided regarding our Named Executive Officers for the
last three fiscal years during which they were our executive officers, if
applicable.

BONUS(1)
NAME AND YEAR ENDED ---------------------------
PRINCIPAL POSITIONS DEC. 31, SALARY CASH STOCK
- ----------------------------- ------------ ----------- ------------------- -------

David L. Sokol .............. 2001 $ 750,000 $ 2,400,000 $ --
Chairman and Chief 2000 $ 750,000 $ 4,250,000 $ --
Executive Officer 1999 $ 675,000 $ 3,276,049 $ --

Gregory E. Abel ............. 2001 $ 520,000 $ 1,150,000 $ --
President and Chief 2000 $ 500,000 $ 1,100,000 $ --
Operating Officer 1999 $ 357,933 $ 1,452,234 $ --

Ronald W. Stepien ...........
President, 2001 $ 400,000 $ 275,000 $ --
MidAmerican 2000 $ 370,667 $ 641,938 $ --
Energy(4) 1999 $ 350,000 $ 1,052,069 $ --

Patrick J. Goodman .......... 2001 $ 240,000 $ 260,000 $ --
Chief Financial 2000 $ 230,000 $ 1,183,071(5) $ --
Officer 1999 $ 199,279 $ 334,374 $ --

Douglas L. Anderson ......... 2001 $ 154,427 $ 200,000 $ --
General Counsel and 2000 $ 120,000 $ 591,806(5) $ --
Corporate Secretary 1999 $ 110,000 $ 40,000 $ --

OTHER RESTRICTED SECURITIES ALL
NAME AND ANNUAL STOCK UNDERLYING LTIP OTHER
PRINCIPAL POSITIONS COMP(2) AWARDS OPTIONS PAYOUTS COMP(3)
- ----------------------------- --------- ------------ ------------ ----------- ----------

David L. Sokol .............. $ -- $ -- -- $ -- $33,037
Chairman and Chief $ -- $ -- 2,199,277 $ -- $40,430
Executive Officer $ -- $ -- -- $ -- $41,519

Gregory E. Abel ............. $ -- $ -- -- $ -- $23,657
President and Chief $ -- $ -- 649,052 $ -- $27,530
Operating Officer $ -- $ -- -- $ -- $27,803

Ronald W. Stepien ...........
President, $7,270 $ -- -- $316,021 $ 6,630
MidAmerican $ -- $ -- -- $ -- $ 6,630
Energy(4) $ -- $ -- 56,203 $ -- $ 6,240

Patrick J. Goodman .......... $ -- $ -- -- $ -- $13,527
Chief Financial $ -- $ -- -- $ -- $14,891
Officer $ -- $ -- 60,000 $ -- $14,719

Douglas L. Anderson ......... $ -- $ -- -- $ -- $ 6,630
General Counsel and $ -- $ -- -- $ -- $ 6,630
Corporate Secretary $ -- $ -- 5,000 $ -- $ 3,654

- ----------

(1) Includes amounts voluntarily deferred by the executive, if applicable.
Includes various expatriate compensation items, including expatriate
allowances, company provided transportation, housing and tax benefits.

(2) Includes payout of earnings on Long-Term Incentive Partnership Plan.

(3) Consists of 401(k) Plan contributions for 2001 for each Executive Officer
listed above in the amount of $6,630. To offset its obligations under the
Company's Executive Split Dollar Plan for executives whose retirement
benefit cannot be fully funded through the Company's Base Retirement Plan
for Salaried Employees, the Company has agreed to pay the premiums for
policies of split dollar life insurance on the lives of such executives.
Included in this column is the value of premiums paid in 2001 for Mr. Sokol
of $25,507, for Mr. Abel of $16,569, and for Mr. Goodman of $6,705. Also
included are the insurance premiums in the following amounts paid by the
Company with respect to the term life insurance portion of premiums paid in
2001 for Mr. Sokol of $900, for Mr. Abel of $457 and for Mr. Goodman of
$192.

(4) Mr. Stepien retired effective December 31, 2001.

(5) Includes cash amounts received upon cash-out of equity in connection with
our acquisition by a private investor group on March 14, 2000.

OPTION GRANTS IN LAST FISCAL YEAR

We did not grant any options during 2001.

AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR END OPTION
VALUES

The following table sets forth the option exercises and the number of
securities underlying exercisable and unexercisable options held by each of our
Named Executive Officers at December 31, 2001.

UNDERLYING UNEXERCISED VALUE OF UNEXERCISED
OPTIONS HELD (#) IN-THE-MONEY OPTIONS ($)(1)
SHARES ACQUIRED ON ----------------------------- ----------------------------
NAME EXERCISE (#) VALUE REALIZED ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ----------------------------- ------------------- -------------------- ------------- --------------- ------------- --------------

David L. Sokol .............. -- -- 1,970,412 228,865 N/A N/A
Gregory E. Abel ............. -- -- 584,864 64,188 N/A N/A
Ronald W. Stepien ........... -- -- -- -- -- --
Patrick J. Goodman .......... -- -- -- -- -- --
Douglas L. Anderson ......... -- -- -- -- -- --

- ----------

(1) On March 14, 2000 we were acquired by a private investor group. As a
privately held company, we have no publicly traded equity securities and,
consequently, our management does not believe there is a reliable method of
computing the present value of the stock options granted to Messrs. Sokol
and Abel as shown on the foregoing table.

LONG-TERM INCENTIVE PLANS--AWARDS IN LAST FISCAL YEAR

NUMBER OF PERFORMANCE OR
SHARES, UNITS OTHER PERIOD UNTIL
OR OTHER MATURATION
NAME RIGHTS (#)(1) OR PAYOUT THRESHOLD ($) TARGET ($)(2) MAXIMUM(#)(3)
- ----------------------------- --------------- ------------------- --------------- --------------- --------------

Ronald W. Stepien ........... N/A December 31, 2005 56,106 N/A N/A(3)
Patrick J. Goodman .......... N/A December 31, 2005 107,212 N/A 360,000
Douglas L. Anderson ......... N/A December 31, 2005 87,769 N/A 231,640.50

- ----------

(1) The awards shown in the foregoing table are made pursuant to the Long-Term
Incentive Partnership Plan, or LTIP, which provides that awards vest
equally over five years with any unvested balances forfeited upon
termination of employment unless the participant retires at or above age 55
with at least 5 years of service in which case the participant will receive
any unvested portion of the award. Vested balances are paid to the
participant at the time of termination. Once an award is fully vested, the
participant may elect to defer or receive payment of part or all of the
award. Messrs. Sokol and Abel are not participants in the LTIP. Awards are
credited or reduced with annual interest or loss based on a composite of
funds or indices.

(2) "Target" and "Threshold" payouts are equivalent with the LTIP.

(3) Because Mr. Stepien is no longer our employee, the maximum payout does not
apply.

COMPENSATION OF DIRECTORS

All directors, excluding Messrs. Sokol, Abel, Buffett and Walter Scott, are
paid an annual retainer fee of $20,000 and a fee of $500 per day for attendance
at Board and Committee meetings. Directors who are our employees are not
entitled to receive such fees. All directors are reimbursed for their expenses
incurred in attending Board meetings.

RETIREMENT PLANS

We maintain a Supplemental Retirement Plan for Designated Officers, which
we refer to as the Supplemental Plan, to provide additional retirement benefits
to designated participants, as determined by the Board of Directors. Messrs.
Sokol, Abel, Stepien and Goodman are participants in the Supplemental Plan. The
Supplemental Plan provides annual retirement benefits up to sixty-five percent
of a participant's Total Cash Compensation in effect immediately prior to
retirement, subject to a $1 million maximum retirement benefit. "Total Cash
Compensation" means the highest amount payable to a participant as monthly base
salary during the five years immediately prior to retirement multiplied by 12
plus the

average of the participant's last three years awards under an annual incentive
bonus program and special, additional or non-recurring bonus awards, if any,
that are required to be included in Total Cash Compensation pursuant to a
participant's employment agreement or approved for inclusion by the Board.
Participants must be credited with five years service in order to be eligible to
receive benefits under the Supplemental Plan. Each of our Named Executive
Officers has or will have five years of credited service with us as of their
respective normal retirement age and will be eligible to receive benefits under
the Supplemental Plan. A participant who elects early retirement is entitled to
reduced benefits under the Supplemental Plan, however, in accordance with their
respective employment agreements, Messrs. Sokol and Abel are eligible to receive
the maximum retirement benefit at age 47. A survivor benefit is payable to a
surviving spouse under the Supplemental Plan. Benefits from the Supplemental
Plan will be paid out of general corporate funds; however, through a rabbi
trust, we maintain life insurance on the participants in amounts expected to be
sufficient to fund the after-tax cost of the projected benefits. Deferred
compensation is considered part of the salary covered by the Supplemental Plan.

The supplemental retirement benefit will be reduced by the amount of the
participant's regular retirement benefit under the MidAmerican Energy Company
Cash Balance Retirement Plan, which we refer to as the MidAmerican Retirement
Plan, that became effective January 1, 1997, and by benefits under the
Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan, which we
refer to as the Iowa-Illinois Supplemental Plan, as applicable.

The MidAmerican Retirement Plan replaced retirement plans of predecessor
companies that were structured as traditional, defined benefit plans. Under the
MidAmerican Retirement Plan, each participant has an account, for record
keeping purposes only, to which credits are allocated each payroll period based
upon a percentage of the participant's salary paid in the current pay period.
In addition, all balances in the accounts of participants earn a fixed rate of
interest that is credited annually. The interest rate for a particular year is
based on the constant maturity Treasury yield plus seven-tenths of one
percentage point. At retirement or other termination of employment, an amount
equal to the vested balance then credited to the account is payable to the
participant in the form of a lump sum or a form of annuity for the entire
benefit under the MidAmerican Retirement Plan. Mr. Anderson is a participant in
this plan.

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

TOTAL CASH ESTIMATED ANNUAL BENEFIT AGE AT RETIREMENT
COMPENSATION ------------------------------------------
RETIREMENT ($) 55 60 65
- ------------------------------ ------------ ------------ ------------

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

EMPLOYMENT AGREEMENTS

Pursuant to his employment agreement Mr. Sokol serves as Chairman of our
Board of Directors and Chief Executive Officer. The employment agreement
provides that Mr. Sokol is to receive an annual base

salary of not less than $750,000, senior executive employee benefits and annual
bonus awards that shall not be less than $675,000. Subject to an annual renewal
provision, such agreement is scheduled to expire on August 21, 2003.

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

In the event Mr. Sokol has relinquished his position as Chief Executive
Officer and is subsequently terminated as Chairman of the Board due to death,
disability or other than for cause, he is entitled to any accrued but unpaid
salary plus an amount equal to the aggregate annual salary that would have been
paid to him through the fifth anniversary of the date he commenced his
employment solely as Chairman of the Board, the immediate vesting of all of his
options and the continuation of his senior executive employee benefits (or the
economic equivalent thereof) through this fifth anniversary. If Mr. Sokol
relinquishes his position as Chief Executive Officer but offers to remain
employed as the Chairman of the Board, he is to receive a special achievement
bonus equal to two times the sum of his annual salary then in effect and the
greater of his minimum annual bonus or his average annual bonus for the two
preceding years, as well as two years of accelerated option vesting.

Under the terms of separate employment agreements between us and each of
Messrs. Abel and Goodman, each of such executives is entitled to receive two
years base salary continuation, payments in respect of average bonuses for the
prior two years and two years continued option vesting in the event we terminate
his employment other than for cause. If such persons were terminated without
cause, Messrs. Sokol, Abel and Goodman would currently be entitled to be paid
approximately $12,375,000, $3,330,000 and $1,006,000, respectively, without
giving effect to any tax related provisions.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information regarding beneficial
ownership of the shares of our common stock and certain information with respect
to the beneficial ownership of each director, our Named Executive Officers and
all directors and executive officers as a group as of November 1, 2002.

NUMBER OF SHARES PERCENTAGE
NAME AND ADDRESS OF BENEFICIAL OWNER (1) BENEFICIALLY OWNED (2) OF CLASS (2)
- ---------------------------------------------- ------------------------ -------------

Common Stock:
Gregory E. Abel (3) ................... 696,433 7.02%
Douglas L. Anderson ................... -- --
Edgar D. Aronson ...................... -- --
Berkshire Hathaway (4) ................ 900,942 9.71%
Stanley J. Bright ..................... -- --
John K. Boyer ......................... -- --
Warren E. Buffett (5) ................. -- --
Patrick J. Goodman .................... -- --
Marc D. Hamburg (5) ................... -- --
Richard R. Jaros ...................... -- --
W. David Scott (6) .................... 624,350 6.73%
Walter Scott, Jr. (7) ................. 5,000,000 53.87%
David L. Sokol (8) .................... 1,692,967 15.89%
All directors and executive officers as
a group (13 persons) ................. 8,914,692 78.96%

- ----------

(1) Unless otherwise indicated, each address is c/o us at 666 Grand Avenue,
29th Floor, Des Moines, Iowa 50309.

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

(3) Includes options to purchase 640,493 shares of common stock which are
exercisable within 60 days.

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

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

(6) Includes shares held by trusts for the benefit of or controlled by W. David
Scott. Such beneficial owner's address is 402 South 36th Street, Suite 800,
Omaha, Nebraska 68131.

(7) Excludes 3 million shares held by family members and family controlled
trusts and corporations ("Scott Family Interests"), including the 624,350
shares shown as beneficially owned by W. David Scott in the table above, as
to all of which shares Mr. Walter Scott disclaims beneficial ownership.
Such beneficial owner's address is 1000 Kiewit Plaza, Omaha, Nebraska
68131.

(8) Includes options to purchase 1,368,762 shares of common stock which are
exercisable within 60 days.

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

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

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

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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

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

In order to finance our $275 million preferred stock investment in
Williams, on March 7, 2002, we sold to Berkshire Hathaway shares of our zero
coupon convertible preferred stock. In order to finance our acquisition of Kern
River, on March 12, 2002, we sold to Berkshire Hathaway and/or its consolidated
subsidiaries shares of our no par, zero coupon convertible preferred stock for
$127 million and $323 million of 11% mandatorily redeemable preferred securities
of our subsidiary trust due March 12, 2012 with scheduled principal payments
beginning in 2005. In order to finance our acquisition of Northern Natural Gas,
on August 16, 2002, we sold to Berkshire Hathaway and/or its consolidated
subsidiaries $950 million of 11% mandatorily redeemable preferred securities of
our subsidiary trust due August 31, 2012 with scheduled principal payments
beginning in 2003. Messrs. Warren E. Buffett and Walter Scott, Jr. are members
of the Board of Directors of Berkshire Hathaway. Messrs. Buffett and Marc D.
Hamburg are executive officers of Berkshire Hathaway. Each of Messrs. Buffett,
Hamburg and Walter Scott serves on our Board of Directors and participates in
deliberations regarding executive officer compensation.

On March 6, 2002, we purchased options to purchase shares of our common
stock from Mr. David L. Sokol, our Chairman and Chief Executive Officer. The
options purchased had exercise prices ranging from $18.50 to $24.22. We paid Mr.
Sokol an aggregate amount of $27,122,550, which is equal to the difference
between his option exercise prices and an agreed upon per share value. Mr. Sokol
serves on our Board of Directors and participates in deliberations regarding
executive officer compensation.

100

In July 2002, we purchased 557,686 options to purchase shares of
HomeServices common stock from directors, officers and employees of
HomeServices. The options purchased had exercise prices ranging from $11.3125 to
$15.00. We paid an aggregate of $4,268,392, which is equal to the difference
between the option exercise prices and an agreed upon per share value.

We have not purchased any other options or securities from our
stockholders, directors or executive officers since January 1, 2002.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

There is no compensation committee of the Board of Directors. All members
of the Board of Directors participate in deliberations regarding executive
officer compensation. Messrs. Sokol and Abel are current officers and employees.
Mr. Walter Scott is a former officer. Mr. Jaros is a former officer and
employee. See --"Certain Relationships and Related Transactions."

101

DESCRIPTION OF THE NOTES

The original notes were, and the exchange notes will be, issued pursuant to
an indenture, dated as of October 4, 2002, between the Company and The Bank of
New York, as trustee. The terms of the notes include those stated in the
indenture and those made part of the indenture by reference to the Trust
Indenture Act of 1939, as amended.

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

GENERAL

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

The notes were initially offered in the aggregate principal amount of
$700,000,000. We may, without the consent of the holders, increase such
principal amount in the future on the same terms and conditions and with the
same CUSIP number(s) as the notes.

The notes were issued in two series. The 2007 notes were issued in an
aggregate principal amount of $200,000,000. The 2007 notes bear interest at the
rate of 4.625% per annum and will mature on October 1, 2007. The 2012 notes were
issued in an aggregate principal amount of $500,000,000. The 2012 notes bear
interest at the rate of 5.875% per annum and will mature on October 1, 2012.
Interest on the notes is payable semi-annually in arrears on each January 31 and
July 31, commencing January 31, 2003, to the holders thereof at the close of
business on the preceding January 15 and July 15, respectively. Interest on the
notes is computed on the basis of a 360-day year of twelve 30-day months.

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

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

If (1) the registration statement of which this prospectus is a part is not
declared effective by the SEC within 270 days after the date on which the
original notes were issued, (2) a shelf registration statement with respect to
the resale of the notes is not declared effective by the SEC within 150 days
after the Company's obligation to file such shelf registration statement arises
(but in any event not prior to 270 days after the date on which the original
notes were issued) or (3) any of the foregoing registration statements (or the
prospectuses related thereto) after being declared effective by the SEC cease to
be so effective or usable (subject to certain exceptions) in connection with
resales of the original notes or exchange notes for the periods specified and in
accordance with the registration rights agreement, the interest rate on the
notes that are then subject to such cessation or other registration default will
increase by 0.5% from and including the date on which any such event occurs
until such event ceases to be continuing. The registration rights are more fully
described under "Exchange Offer--Liquidated Damages."

Any 2007 original notes that remain outstanding after the consummation of
the exchange offer, together with all 2007 exchange notes issued in connection
with the exchange offer, will be treated as a single class of securities under
the indenture. Any 2012 original notes that remain outstanding after the
consummation of the exchange offer, together with all 2012 exchange notes issued
in connection with the exchange offer, will be treated as a single class of
securities under the indenture.

102

OPTIONAL REDEMPTION

GENERAL

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

(1) 100% of the principal amount of the series of notes being redeemed; or

(2) the sum of the present values of the remaining scheduled payments of
principal of and interest on the series of notes being redeemed
discounted to the date of redemption on a semiannual basis (assuming a
360-day year consisting of twelve 30-day months) at a discount rate
equal to the Treasury Yield plus 37.5 basis points,

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

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

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

OPTIONAL REDEMPTION PROVISIONS

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

The Present Value at any time of a payment of principal of or interest on a
note is calculated by applying to such payment the discount rate (the "Discount
Rate") applicable to such payment. The Discount Rate applicable at any time to
payment of principal of or interest on a note equals the equivalent yield to
maturity at such time of a fixed rate United States treasury security having a
maturity comparable to the maturity of such payment plus 37.5 basis points, such
yield being calculated on the basis of the interest rate borne by such United
States treasury security and the price at such time of such security. The United
States treasury security employed in the calculation of a Discount Rate (a
"Relevant Security") as well as the price and equivalent yield to maturity of
such Relevant Security will be selected or determined by an Independent
Investment Banker.

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

103

issued United States treasury security having a maturity comparable to that of
a Relevant Security is lower than the level of interest rates prevailing for
newly issued United States treasury securities having a maturity comparable to
the Relevant Security at the time the Relevant Security was issued, the price
of the Relevant Security will be higher than its issue price.

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

SINKING FUND

The notes are not subject to any mandatory sinking fund.

RANKING

The notes are general, unsecured senior obligations of the Company and rank
pari passu in right of payment with all other existing and future senior
unsecured obligations of the Company and senior in right of payment to all
existing and future subordinated obligations of the Company. The notes are
effectively subordinated to all existing and future secured obligations of the
Company and to all existing and future obligations of the Company's
Subsidiaries. At September 30, 2002, the Company's outstanding indebtedness was
approximately $2.0 billion (excluding $2.1 billion in aggregate principal amount
of the Company's trust preferred securities, the Company's guarantees and
letters of credit in respect of subsidiary indebtedness aggregating
approximately $235 million and the Company's completion guarantee issued in
favor of the lenders under Kern River's $875 million construction loan facility
in connection with Kern River's 2003 Expansion Project). In addition, the
Company's subsidiaries have significant amounts of indebtedness. At September
30, 2002, the Company's consolidated subsidiaries' and joint ventures' total
outstanding indebtedness was approximately $7.1 billion, which does not include
$453 million, representing the Company's share of outstanding indebtedness of CE
Gen. This amount also does not include trade debt of the Company's subsidiaries.
See "Capitalization."

COVENANTS

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

RESTRICTIONS ON LIENS

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

104

(1) any Liens existing prior to the issuance of the original notes;

(2) purchase money Liens which do not exceed the cost or value of the
purchased property or assets;

(3) any Liens not to exceed 10% of Consolidated Net Tangible Assets; and

(4) any Liens on property or assets granted in connection with extending,
renewing, replacing or refinancing in whole or in part the
Indebtedness for Borrowed Money (including, without limitation,
increasing the principal amount of such Indebtedness for Borrowed
Money) secured by Liens described in the foregoing clauses (1) through
(3), provided that the Liens in connection with any such extension,
renewal, replacement or refinancing will be limited to the specific
property or assets that was subject to the original Lien.

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

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

CONSOLIDATION, MERGER, CONVEYANCE, SALE OR LEASE

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

Except for a sale of the consolidated properties and assets of the Company
substantially as an entirety as provided above, and other than properties or
assets required to be sold to conform with laws or governmental regulations,
the Company is not permitted, directly or indirectly, to sell or otherwise
dispose of any of its consolidated properties or assets (other than short-term,
readily marketable investments purchased for cash management purposes with
funds not representing the proceeds of other asset sales) if on a pro forma
basis, the aggregate net book value of all such sales during the most recent
12-month period would exceed 10% of Consolidated Net Tangible Assets computed
as of the end of the most recent quarter preceding such sale; provided,
however, that (1) any such sales shall be disregarded for purposes of this 10%
limitation if the net proceeds are invested in properties or assets in similar
or related lines of business of the Company and its Subsidiaries, including,
without limitation, any of the lines of business in which the Company or any of
its Subsidiaries is engaged on the date of such sale or disposition, and (2)
the Company may sell or otherwise dispose of consolidated properties and assets
in excess of such 10% limitation if the net proceeds from such sales or
dispositions, which are not reinvested as provided above, are retained by the
Company as cash or Cash Equivalents or used to retire Indebtedness for Borrowed
Money of the Company (other than Indebtedness for Borrowed Money which is
subordinated to the notes) and its Subsidiaries.

PURCHASE OF NOTES UPON A CHANGE OF CONTROL

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

105

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

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

(1) that a Change of Control has occurred and that such holder has the
right to require the Company to purchase such holder's notes at the
purchase price described above (the "Change of Control Offer");

(2) the circumstances and relevant facts regarding such Change of Control
(including information with respect to pro forma historical income,
cash flow and capitalization after giving effect to such Change of
Control);

(3) the purchase date (which will be not earlier than 30 days nor later
than 60 days from the date such notice is mailed) (the "Purchase
Date");

(4) that after the Purchase Date interest on such note will continue to
accrue (except as provided in clause (5));

(5) that any note properly tendered pursuant to the Change of Control
Offer will cease to accrue interest after the Purchase Date (assuming
sufficient moneys for the purchase thereof are deposited with the
trustee);

(6) that holders electing to have a note of any series purchased pursuant
to a Change of Control Offer will be required to surrender the note of
such series, with the form entitled "Option of Holder To Elect
Purchase" on the reverse of the note completed, to the paying agent at
the address specified in the notice prior to the close of business on
the fifth business day prior to the Purchase Date;

(7) that a holder will be entitled to withdraw such holder's election if
the paying agent receives, not later than the close of business on the
third business day (or such shorter periods as may be required by
applicable law) preceding the Purchase Date, a telegram, telex,
facsimile transmission or letter setting forth the name of the holder,
the principal amount of notes of such series the holder delivered for
purchase, and a statement that such holder is withdrawing his election
to have such notes of such series purchased; and

(8) that holders that elect to have their notes of any series purchased
only in part will be issued new notes having a principal amount equal
to the portion of the notes of the series that were surrendered but
not tendered and purchased.

On the Purchase Date, the Company will (1) accept for payment all notes of
any series or portions thereof tendered pursuant to the Change of Control Offer,
(2) deposit with the trustee money sufficient to pay the purchase price of all
notes of such series or portions thereof so tendered for purchase and (3)
deliver or cause to be delivered to the trustee the notes of such series
properly tendered together with an officer's certificate identifying the notes
of such series or portions thereof tendered to the Company for purchase. The
trustee will promptly mail, to the holders of the notes of such series properly
tendered and purchased, payment in an amount equal to the purchase price, and
promptly authenticate and mail to each holder a new note of the same series
having a principal amount equal to any portion of such holder's notes of such
series that were surrendered but not tendered and purchased. The Company will
publicly announce the results of the Change of Control Offer on or as soon as
practicable after the Purchase Date.

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

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

EVENTS OF DEFAULT

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

(1) default as to the payment of interest on any note of that series for
30 days after payment is due;

(2) default as to the payment of principal of, or premium, if any, on any
note of that series or as to any payment required in connection with a
Change of Control;

(3) failure to make a Change of Control Offer required under the covenants
described under "Purchase of Notes Upon a Change of Control" above or
a failure to purchase the notes of that series tendered in respect of
such Change of Control Offer;

(4) default in the performance, or breach, of any covenant, agreement or
warranty of the Company contained in the indenture and the notes of
that series and such failure continues for 30 days after written
notice is given to the Company by the trustee or to the Company and
the trustee by the holders of at least a majority in aggregate
principal amount outstanding of the notes of that series, as provided
in the indenture;

(5) default on any other Debt of the Company or any Significant Subsidiary
(other than Debt that is Non-Recourse to the Company) if either (x)
such default results from failure to pay principal of such Debt in
excess of $100 million when due after any applicable grace period or
(y) as a result of such default, the maturity of such Debt has been
accelerated prior to its scheduled maturity and such default has not
been cured within the applicable grace period, and such acceleration
has not been rescinded, and the principal amount of such Debt,
together with the principal amount of any other Debt of the Company
and its Significant Subsidiaries (not including Debt that is
Non-Recourse to the Company) that is in default as to principal, or
the maturity of which has been accelerated, aggregates $100 million or
more;

(6) the entry by a court of one or more judgments or orders against the
Company or any Significant Subsidiary for the payment of money that in
the aggregate exceeds $100 million (excluding (i) the amount thereof
covered by insurance or by a bond written by a person other than an
affiliate of the Company and (ii) judgments that are Non-Recourse to
the Company), which judgments or orders have not been vacated,
discharged or satisfied or stayed pending appeal within 60 days from
the entry thereof, provided that such a judgment or order will not be
an event of default if such judgment or order does not require any
payment by the Company; and

(7) certain events involving bankruptcy, insolvency or reorganization of
the Company or any of its Significant Subsidiaries.

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

The indenture provides that if an event of default with respect to the
notes of any series at the time outstanding (other than an event of bankruptcy,
insolvency or reorganization of the Company or a Significant Subsidiary) has
occurred and is continuing, either the trustee or (i) in the case of any event
of default described in clause (1) or (2) above, the holders of at least 33% in
aggregate principal amount of the notes of that series then outstanding, or
(ii) in the case of any other event of default, the holders of at least a
majority in aggregate principal amount of the notes of that series then
outstanding, may declare the principal of and any accrued interest on all notes
of that series to be due and payable immediately, but upon certain conditions
such declaration may be annulled and past defaults (except, unless theretofore
cured, a default in payment of principal of, premium, if any, or interest on
the notes of that series or any payment required in connection with a Change of
Control) may be waived by the holders of a majority in principal amount of the
notes of that series then outstanding. If an event of default due to the

107

bankruptcy, insolvency or reorganization of the Company or a Significant
Subsidiary occurs, the indenture provides that the principal of and interest on
all notes of that series will become immediately due and payable without any
action by the trustee, the holders of notes or any other person.

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

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

MODIFICATION OF THE INDENTURE

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

DEFEASANCE AND DISCHARGE

LEGAL DEFEASANCE

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

(A) the Company has deposited with the trustee, in trust, money and/or
U.S. Government Obligations that through the payment of interest and
principal in respect thereof in accordance with their terms will
provide money in an amount sufficient to pay the principal of,
premium, if any, and accrued and unpaid interest on the applicable
notes, on the respective stated maturities of the notes or, if the
Company makes arrangements satisfactory to the trustee for the
redemption of the notes prior to their stated maturity, on any earlier
redemption date in accordance with the terms of the indenture and the
applicable notes;

(B) the Company has delivered to the trustee:

(1) either (x) an opinion of counsel to the effect that holders will
not recognize income, gain or loss for federal income tax
purposes as a result of such deposit, defeasance and discharge
and will be subject to federal income tax on the same amount and
in the same manner and at the same times as would have been the
case if such deposit, defeasance and discharge had not occurred
and the Company had paid or redeemed such notes on the applicable
dates, which opinion of counsel must be based upon a ruling of
the Internal Revenue Service to

108

the same effect or a change in applicable federal income tax law
or related Treasury regulations after the date of the indenture,
or (y) a ruling directed to the trustee or the Company received
from the Internal Revenue Service to the same effect as the
aforementioned opinion of counsel;

(2) an opinion of counsel to the effect that the creation of the
defeasance trust does not violate the Investment Company Act of
1940; and

(3) an opinion of counsel to the effect that either (x) after the
passage of 123 days following the deposit referred to in clause
(A) above, the trust fund will not be subject to the effect of
Section 547 or 548 of the U.S. Bankruptcy Code or Section 15 of
the New York Debtor and Creditor Law or (y) based upon existing
precedents, if the matter were properly briefed, a court should
hold that the deposit of moneys and/or U.S. Government
Obligations as provided in clause (A) above would not constitute
a preference voidable under Section 547 or 548 of the U.S.
Bankruptcy Code or Section 15 of the New York Debtor and Creditor
Law;

(C) immediately after giving effect to such deposit referred to in clause
(A) above on a pro forma basis, no event of default under the
indenture, or event that after the giving of notice or lapse of time
or both would become an event of default, will have occurred and be
continuing on the date of such deposit or (unless an opinion of
counsel is delivered to the effect described in clause (B)(3)(y)
above) during the period ending on the 123rd day after the date of
such deposit, and such deposit and discharge will not result in a
breach or violation of, or constitute a default under, any other
material agreement or instrument to which the Company is a party or by
which the Company is bound; and

(D) if at such time the notes are listed on a national securities
exchange, the Company has delivered to the trustee an opinion of
counsel to the effect that the notes will not be delisted as a result
of such deposit, defeasance and discharge.

COVENANT DEFEASANCE

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

DEFEASANCE AND CERTAIN OTHER EVENTS OF DEFAULT

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

GOVERNING LAW

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

109

TRUSTEE

The Bank of New York is the trustee under the indenture. An affiliate of
the trustee was an initial purchaser in the offering of the original notes. The
Bank of New York (or one of its affiliates) currently serves, and may in the
future serve, as trustee under indentures evidencing other indebtedness of the
Company and its affiliates. The Bank of New York (or one of its affiliates) is
also, and may in the future be, a lender under credit facilities for the Company
and its affiliates. The Bank of New York is also the exchange agent in the
exchange offer.

DEFINITIONS

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

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

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

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

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

"Cash Equivalent" means any of the following:

(1) securities issued or directly and fully guaranteed or insured by the
United States of America or any agency or instrumentality thereof
(provided that the full faith and credit of the United States of
America is pledged in support thereof);

(2) time deposits and certificates of deposit of any commercial bank
organized in the United States having capital and surplus in excess of
$500,000,000 or any commercial bank organized under the laws of any
other country having total assets in excess of $500,000,000 with a
maturity date not more than two years from the date of acquisition;

(3) repurchase obligations with a term of not more than 30 days for
underlying securities of the types described in clauses (1) or (5) of
this definition that were entered into with any bank meeting the
qualifications set forth in clause (2) of this definition or another
financial institution of national reputation;

(4) direct obligations issued by any state or other jurisdiction of the
United States of America or any other country or any political
subdivision or public instrumentality thereof maturing, or subject to
tender at the option of the holder thereof, within 90 days after the
date of acquisition thereof and, at the time of acquisition, having a
rating of at least A from S&P or A-2 from Moody's (or, if at any time
neither S&P nor Moody's may be rating such obligations, then from
another nationally recognized rating service acceptable to the
trustee);

(5) commercial paper issued by (a) the parent corporation of any
commercial bank organized in the United States having capital and
surplus in excess of $500,000,000 or any commercial bank organized
under the laws of any other country having total assets in excess of
$500,000,000, and (b) others having one of the two highest ratings
obtainable from either S&P or Moody's (or, if at

110

any time neither S&P nor Moody's may be rating such obligations, then
from another nationally recognized rating service acceptable to the
trustee) and in each case maturing within one year after the date of
acquisition;

(6) overnight bank deposits and bankers' acceptances at any commercial
bank organized in the United States having capital and surplus in
excess of $500,000,000 or any commercial bank organized under the laws
of any other country having total assets in excess of $500,000,000;

(7) deposits available for withdrawal on demand with any commercial bank
organized in the United States having capital and surplus in excess of
$500,000,000 or any commercial bank organized under the laws of any
other country having total assets in excess of $500,000,000;

(8) investments in money market funds substantially all of whose assets
comprise securities of the types described in clauses (1) through (6)
and (9) of this definition; and

(9) auction rate securities or money market preferred stock having one of
the two highest ratings obtainable from either S&P or Moody's (or, if
at any time neither S&P nor Moody's may be rating such obligations,
then from another nationally recognized rating service acceptable to
the trustee).

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

(1) a transaction pursuant to which Berkshire Hathaway ceases to own, on a
diluted basis (assuming conversion of all of the Company's convertible
preferred stock and any other Capital Stock of the Company that is
issued and outstanding, regardless of whether any such convertible
preferred stock or other Capital Stock is then presently convertible),
at least a majority of the issued and outstanding common stock of the
Company; or

(2) the Company or its Subsidiaries sell, convey, assign, transfer, lease
or otherwise dispose of all or substantially all the property of the
Company and its Subsidiaries taken as a whole to any person or entity
other than an entity at least a majority of the issued and outstanding
common stock of which is owned by Berkshire Hathaway, calculated on a
diluted basis as described above;

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

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

"Comparable Treasury Price" means, with respect to any Redemption Date, (1)
the average of the bid and asked prices for the Comparable Treasury Issue
(expressed in each case as a percentage of its principal amount) on the third
business day preceding such Redemption Date, as set forth in the daily
statistical release (or any successor release) published by the Federal Reserve
Bank of New York and designated "Composite 3:30 p.m. Quotations for U.S.
Government Securities" or (2) if such release (or any successor release) is not
published or does not contain such prices on such business day, the Reference
Treasury Dealer Quotation for such Redemption Date.

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

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

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

111

(1) all Indebtedness for Borrowed Money of such person;

(2) all obligations of such person evidenced by bonds, debentures, notes
or other similar instruments;

(3) all obligations of such person in respect of letters of credit,
bankers' acceptances, surety, bid, operating and performance bonds,
performance guarantees or other similar instruments or obligations (or
reimbursement obligations with respect thereto) (except, in each case,
to the extent incurred in the ordinary course of business);

(4) all obligations of such person to pay the deferred purchase price of
property or services, except Trade Payables;

(5) the Attributable Value of all obligations of such person as lessee
under Capitalized Leases;

(6) all Debt of others secured by a Lien on any Property of such person,
whether or not such Debt is assumed by such person, provided that, for
purposes of determining the amount of any Debt of the type described
in this clause, if recourse with respect to such Debt is limited to
such Property, the amount of such Debt will be limited to the lesser
of the fair market value of such Property or the amount of such Debt;

(7) all Debt of others Guaranteed by such person to the extent such Debt
is Guaranteed by such person;

(8) all Redeemable Stock valued at the greater of its voluntary or
involuntary liquidation preference plus accrued and unpaid dividends;
and

(9) to the extent not otherwise included in this definition, all net
obligations of such person under Currency Protection Agreements and
Interest Rate Protection Agreements.

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

"Guarantee" means any obligation, contingent or otherwise, of any person
directly or indirectly guaranteeing any Debt of any other person and, without
limiting the generality of the foregoing, any Debt obligation, direct or
indirect, contingent or otherwise, of such person (1) to purchase or pay (or
advance or supply funds for the purchase or payment of) such Debt of such other
person (whether arising by virtue of partnership arrangements (other than solely
by reason of being a general partner of a partnership), or by agreement to
keep-well, to purchase assets, goods, securities or services or to take-or-pay,
or to maintain financial statement conditions or otherwise) or (2) entered into
for purposes of assuring in any other manner the obligee of such Debt of the
payment thereof or to protect such obligee against loss in respect thereof (in
whole or in part), provided that the term "Guarantee" will not include
endorsements for collection or deposit in the ordinary course of business or the
grant of a lien in connection with any Non-Recourse Debt. The term "Guarantee"
used as a verb has a corresponding meaning.

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

"Intangible Assets" means, as of the date of determination thereof, all
assets of the Company properly classified as intangible assets determined on a
consolidated basis in accordance with GAAP.

"Interest Rate Protection Agreement" means, with respect to any person, any
interest rate protection agreement, interest rate future agreement, interest
rate option agreement, interest rate swap agreement, interest rate cap
agreement, interest rate collar agreement, interest rate hedge agreement or
other similar agreement or arrangement intended to protect such person against
fluctuations in interest rates to or under which such person or any of its
Subsidiaries is a party or a beneficiary on the date of the indenture or becomes
a party or a beneficiary thereafter.

112

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

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

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

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

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

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

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

"Rating Decline" is defined to mean the occurrence of the following on, or
within 90 days after, the earlier of (1) the occurrence of a Change of Control
and (2) the date of public notice of the occurrence of a Change of Control or of
the public notice of the intention of the Company to effect a Change of Control
(the "Rating Date"), which period will be extended so long as the rating of the
notes is under publicly announced consideration for possible downgrading by any
of the Rating Agencies: (a) in the event that any series of the notes are rated
by either Rating Agency on the Rating Date as Investment Grade, the rating of
such notes by both such Rating Agencies will be reduced below Investment Grade,
or (b) in the event the notes are rated below Investment Grade by both such
Rating Agencies on the Rating Date, the rating of such notes by either Rating
Agency will be decreased by one or more gradations (including gradations within
Rating Categories as well as between Rating Categories).

"Redeemable Stock" means any class or series of Capital Stock of any person
that by its terms or otherwise is (1) required to be redeemed prior to the
stated maturity of any series of the notes, (2) redeemable at the option of the
holder of such class or series of Capital Stock at any time prior to the stated
maturity of any series of the notes or (3) convertible into or exchangeable for
Capital Stock referred to in clause (1) or (2) above or Debt having a scheduled
maturity prior to the stated maturity of any series of the notes, provided that
any Capital Stock that would not constitute Redeemable Stock but for provisions
thereof giving holders thereof the right to require the Company to purchase or
redeem such Capital Stock upon the occurrence of a "change of control" occurring
prior to the stated maturity of any

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series of the notes will not constitute Redeemable Stock if the "change of
control" provisions applicable to such Capital Stock are no more favorable to
the holders of such Capital Stock than the provisions contained in the
covenants described under "Purchase of Notes Upon a Change of Control" above.

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

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

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

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

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

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

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

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

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

GLOBAL NOTES; BOOK-ENTRY SYSTEM

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

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

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

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

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

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

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

Principal (and premium, if any) and interest payments on the notes and any
redemption payments will be made to Cede & Co. (or such other nominee as may be
requested by an authorized representative

115

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

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

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

A Global Note of any series may not be transferred except as a whole by the
Depositary to a nominee or successor of the Depositary or by a nominee of the
Depositary to another nominee of the Depositary. A Global Note representing
notes of any series is exchangeable, in whole but not in part, for notes of such
series in definitive form of like tenor and terms if (1) the Depositary notifies
the Company that it is unwilling or unable to continue as depositary for such
Global Note or if at any time the Depositary is no longer eligible to be or in
good standing as a "clearing agency" registered under the Exchange Act, and in
either case, a successor depositary is not appointed by the Company within 120
days of receipt by the Company of such notice or of the Company becoming aware
of such ineligibility, (2) while such Global Note is subject to the transfer
restrictions described in the indenture, the book-entry interests in such Global
Note cease to be eligible for Depositary services because such notes are neither
(a) rated in one of the top four categories by a nationally recognized
statistical rating organization nor (b) included within a Self-Regulatory
Organization system approved by the SEC for the reporting of quotation and trade
information of securities eligible for transfer pursuant to Rule 144A under the
Securities Act, or (3) the Company in its sole discretion at any time determines
not to have such notes represented by a Global Note and notifies the trustee
thereof. A Global Note exchangeable pursuant to the preceding sentence shall be
exchangeable for notes registered in such names and in such authorized
denominations as the Depositary of such Global Note shall direct.

If (1) the exchange offer registration statement is not declared effective
by the Exchange Effectiveness Deadline, (2) the shelf registration statement is
not declared effective by the Shelf Effectiveness Deadline, or (3) after either
the exchange offer registration statement or the shelf registration statement is
declared effective, such registration statement or the related prospectus
thereafter ceases to be effective or usable (subject to certain exceptions) in
connection with resales of notes or exchange notes for the period specified and
in accordance with the registration rights agreement (each such event referred
to in clauses (1) through (3), a "Registration Default"), additional interest
will accrue on the notes subject to such Registration Default at a rate of 0.5%
from and including the date on which any such Registration Default occurs to but
excluding the date on which all such Registration Defaults have ceased to be
continuing. In each case, such additional interest is payable in addition to any
other interest payable from time to time with respect to the notes and the
exchange notes.

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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following discussion is a summary of the material United States federal
income tax consequences relevant to the purchase, ownership and disposition of
the notes, and does not purport to be a complete analysis of all potential tax
effects. This discussion only deals with persons that hold notes as a capital
asset within the meaning of Section 1221 of the Internal Revenue Code of 1986,
as amended (the "Code"), and that purchased the notes for cash at original
issue. This discussion does not address all the United States federal income tax
consequences that may be relevant to a holder in light of such holder's
particular circumstances or to holders subject to special rules, such as
financial institutions, banks, partnerships and other pass-through entities,
United States expatriates, controlled foreign corporations, passive foreign
investment companies, foreign personal holding companies, insurance companies,
dealers in securities or currencies, traders in securities, U.S. Holders
(defined below) whose functional currency is not the United States dollar,
tax-exempt organizations and persons holding the notes as part of a "straddle,"
"hedge," "conversion transaction" or other integrated transaction.

The discussion is based upon the Code, United States Treasury Regulations
issued thereunder, Internal Revenue Service rulings and pronouncements and
judicial decisions now in effect, all of which are subject to change at any time
possibly with retroactive effect.

As used herein, "U.S. Holder" means a beneficial owner of the notes who or
that is

o an individual that is a citizen or resident of the United States;

o a corporation or other entity taxable as a corporation created or
organized in or under the laws of the United States or a political
subdivision thereof;

o an estate, the income of which is subject to United States federal
income tax regardless of its source;

o a trust, if a United States court can exercise primary supervision
over the administration of the trust and one or more U.S. persons can
control all substantial trust decisions, or, if the trust was in
existence on August 20, 1996, and has elected to continue to be
treated as a U.S. person; or

o a person whose worldwide income or gain is otherwise subject to United
States federal income tax on a net income basis.

We have not sought and will not seek any rulings from the Internal Revenue
Service, (the "IRS") with respect to the matters discussed below. There can be
no assurance that the IRS will not take a different position concerning the tax
consequences of the purchase, ownership or disposition of the notes or that any
such position would not be sustained.

PROSPECTIVE INVESTORS SHOULD CONSULT THEIR OWN TAX ADVISORS WITH REGARD TO
THE APPLICATION OF THE TAX CONSEQUENCES DISCUSSED BELOW TO THEIR PARTICULAR
SITUATIONS AS WELL AS THE APPLICATION OF ANY STATE, LOCAL, FOREIGN OR OTHER TAX
LAWS, INCLUDING GIFT AND ESTATE TAX LAWS.

U.S. HOLDERS

STATED INTEREST

A U.S. Holder must generally include stated interest on a note as ordinary
income at the time such interest is received or accrued, in accordance with such
U.S. Holder's method of accounting for U.S. federal income tax purposes.

SALE OR OTHER TAXABLE DISPOSITION OF THE NOTES

A U.S. Holder will generally recognize gain or loss on the sale, exchange,
redemption, retirement or other taxable disposition of a note equal to the
difference between the amount realized upon the disposition and the U.S.
Holder's adjusted tax basis in the note. Notwithstanding the foregoing, any
amounts realized in connection with any sale, exchange, redemption, retirement
or other taxable disposition to the extent attributable to accrued interest not
previously included in income will be treated

117

as ordinary interest income. A U.S. Holder's adjusted basis in a note generally
will be the U.S. Holder's cost therefor. This gain or loss generally will be a
capital gain or loss, and if the U.S. Holder is an individual that has held the
note for more than one year, such capital gain will generally be subject to tax
at a maximum rate of 20%, or 18% if such holder has held the notes for more
than five years. A U.S. Holder's ability to deduct capital losses may be
limited.

EXCHANGE OFFER

The exchange of original notes for exchange notes pursuant to the exchange
offer will not constitute a taxable event for U.S. federal income tax purposes.
As a result,

o a U.S. Holder of notes will not recognize taxable gain or loss as a
result of the exchange of original notes for exchange notes pursuant
to the exchange offer,

o the holding period of the exchange notes will include the holding
period of the original notes surrendered in exchange therefor, and

o a U.S. Holder's adjusted tax basis in the exchange notes will be the
same as such U.S. Holder's adjusted tax basis in the original notes
surrendered in exchange therefor.

CONTINGENT PAYMENTS

In certain circumstances, we may be obligated to pay you amounts in excess
of the stated interest and principal payable on the notes. The obligation to
make payments of additional interest upon a registration default, and, in
certain circumstances, payments upon a change in control, may implicate the
provisions of Treasury regulations relating to "contingent payment debt
instruments." We intend to take the position that the notes should not be
treated as contingent payment debt instruments because of these payments.
Assuming such position is respected, a U.S. Holder would be required to include
in income the amount of any such payments at the time such payments are received
or accrued in accordance with such U.S. Holder's method of accounting for U.S.
federal income tax purposes. If the IRS successfully challenged this position,
and the notes were treated as contingent payment debt instruments because of
such payments, U.S. Holders might, among other things, be required to accrue
interest income at higher rates than the stated interest rates on the notes and
to treat any gain recognized on the sale or other disposition of a note as
ordinary income, subject to tax at the maximum federal rate of 38.6%, rather
than as capital gain which may be subject to tax at the maximum federal rate of
20%. The regulations applicable to contingent payment debt instruments have not
been the subject of authoritative interpretation and therefore the scope of the
regulations is not certain. Purchasers of notes are urged to consult their tax
advisors regarding the possible application of the contingent payment debt
instrument rules to the notes.

INFORMATION REPORTING AND BACKUP WITHHOLDING

A U.S. Holder may be subject to a backup withholding tax (currently at a
rate of 30% but subject to a gradual reduction to 28% for payments made in 2006
through 2010, after which it will increase to 31%) when such holder receives
"reportable payments," including interest and principal payments on the notes or
proceeds upon the sale or other disposition of such notes. Certain holders
(including, among others, corporations and certain tax-exempt organizations) are
generally not subject to backup withholding. A U.S. Holder will be subject to
this backup withholding tax if such holder is not otherwise exempt and such
holder:

o fails to furnish its taxpayer identification number, or TIN, which,
for an individual, is ordinarily his or her social security number;

o furnishes an incorrect TIN and the payor has received notice thereof;

o has failed to properly report payments of interest or dividends and
the payor has received notice thereof; or

o fails to certify, under penalties of perjury, that it has furnished a
correct TIN and that the IRS has not notified the U.S. Holder that it
is subject to backup withholding.

118

U.S. Holders should consult their personal tax advisors regarding their
qualification for an exemption from backup withholding and the procedures for
obtaining such an exemption, if applicable. The backup withholding tax is not
an additional tax and taxpayers may use amounts withheld as a credit against
their United States federal income tax liability or may claim a refund as long
as they timely provide certain information to the IRS.

We, our paying agent or other withholding agent generally will report to a
U.S. Holder of notes and to the IRS the amount of any reportable payments made
in respect of the notes for each calendar year and the amount of tax withheld,
if any, with respect to such payments.

NON-U.S. HOLDERS

The following discussion is limited to the United States federal income tax
consequences relevant to a beneficial owner of a note that is not a U.S. Holder
(a "Non-U.S. Holder").

INTEREST

Subject to the discussion of backup withholding below, interest paid to a
Non-U.S. Holder will not be subject to United States federal income or
withholding tax, provided that:

o such holder does not directly or indirectly, actually or
constructively, own 10% or more of the total combined voting power of
all classes of our stock entitled to vote;

o such holder is not a controlled foreign corporation that is related to
us directly or constructively through stock ownership;

o such holder is not a bank receiving interest on a loan entered into in
the ordinary course of its trade or business;

o such interest is not effectively connected with the conduct by the
Non-U.S. Holder of a trade or business within the United States; and

o we, or our paying agent, receive appropriate documentation
establishing that the Non-U.S. Holder is not a U.S. person.

A Non-U.S. Holder that does not qualify for exemption from withholding
under the preceding paragraph generally will be subject to withholding of United
States federal income tax at a 30% rate (or lower applicable treaty rate) on
payments of interest on the notes.

If interest on the notes is effectively connected with the conduct by a
Non-U.S. Holder of a trade or business within the United States, such interest
will be subject to United States federal income tax on a net income basis at the
rate applicable to U.S. persons generally (and, with respect to corporate
holders, may also be subject to a 30% branch profits tax). If interest is
subject to United States federal income tax on a net income basis in accordance
with these rules, such payments will not be subject to United States withholding
tax so long as the Non-U.S. Holder provides us or our paying agent with the
appropriate documentation.

SALE OR OTHER TAXABLE DISPOSITION OF THE NOTES

Subject to the discussion of backup withholding below, any gain realized
by a Non-U.S. Holder on the sale, exchange or redemption of a note generally
will not be subject to United States federal income tax, unless

o such gain is effectively connected with the conduct by such Non-U.S.
Holder of a trade or business within the United States,

o the Non-U.S. Holder is an individual who is present in the United
States for 183 days or more in the taxable year of disposition and
certain other conditions are satisfied, or

o the Non-U.S. Holder is subject to tax pursuant to the provisions of
United States federal income tax law applicable to certain
expatriates.

119

INFORMATION REPORTING AND BACKUP WITHHOLDING

Backup withholding and information reporting generally will not apply to
interest payments made to a Non-U.S. Holder in respect of the notes if such
Non-U.S. Holder furnishes us or our paying agent with appropriate documentation
of such holder's non-U.S. status.

The payment of proceeds from a Non-U.S. Holder's disposition of notes to
or through the U.S. office of any broker, domestic or foreign, will be subject
to information reporting and possible backup withholding unless such holder
certifies as to its non-U.S. status under penalties of perjury or otherwise
establishes an exemption, provided that the broker does not have actual
knowledge or reason to know that such holder is a U.S. person or that the
conditions of an exemption are not, in fact, satisfied.

The payment of the proceeds from a Non-U.S. Holder's disposition of a note
to or through a non- United States office of either a United States broker or a
non- United States broker that is a U.S.-related person will be subject to
information reporting, but not backup withholding, unless such broker has
documentary evidence in its files that such Non-U.S. Holder is not a U.S. person
and the broker has no knowledge to the contrary, or the Non-U.S. Holder
establishes an exemption. For this purpose, a "U.S.-related person" is

o a controlled foreign corporation for United States federal income tax
purposes,

o a foreign person 50% or more of whose gross income from all sources
for the three-year period ending with the close of its taxable year
preceding payment (or for such part of the period that the broker has
been in existence) is derived from activities that are effectively
connected with the conduct of a United States trade or business, or

o a foreign partnership that is either engaged in the conduct of a trade
or business in the United States or of which 50% or more of its income
or capital interests are held by U.S. persons.

Neither information reporting nor backup withholding will apply to a
payment of the proceeds of a Non-U.S. Holder's disposition of notes by or
through a non-United States office of a non-United States broker that is not a
United States-related person. Copies of any information returns filed with the
IRS may be made available by the IRS, under the provisions of a specific treaty
or agreement, to the taxing authorities of the country in which the Non-U.S.
Holder resides.

Non-U.S. Holders should consult their own tax advisors regarding the
application of withholding and backup withholding in their particular
circumstances and the availability of and procedure for obtaining an exemption
from withholding and backup withholding under current Treasury Regulations. In
this regard, the current Treasury Regulations provide that a certification may
not be relied on if we or our agent (or other payor) knows or has reasons to
know that the certification may be false.

Any amounts withheld under the backup withholding rules from a payment to a
Non-U.S. Holder will be allowed as a credit against the holder's United States
federal income tax liability or may entitle the holder to a refund, provided the
required information is furnished timely to the IRS.

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PLAN OF DISTRIBUTION

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

Each broker-dealer that receives exchange notes for its own account
pursuant to the exchange offer must acknowledge that it will deliver a
prospectus in connection with any resale of such exchange notes. This
prospectus, as it may be amended or supplemented from time to time, may be used
by a broker-dealer in connection with resales of exchange notes received in
exchange for original notes where such original notes were acquired as a result
of market-marketing activities or other trading activities. We have agreed that,
for a period of 120 days after the expiration date, we will make this
prospectus, as amended or supplemented, available to any broker-dealer for use
in connection with any such resale. In addition, until _________, 200___, all
dealers effecting transactions in the exchange notes may be required to deliver
a prospectus.

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

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

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NOTICE TO CANADIAN RESIDENTS

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

LEGAL MATTERS

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

EXPERTS

The consolidated balance sheets of MidAmerican Energy Holdings Company
(successor to MidAmerican Energy Holdings Company (Predecessor), or MEHC
(Predecessor)), and its subsidiaries, which are therein collectively referred to
as the Company, as of December 31, 2001 and 2000 for the Company, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for the year ended December 31, 2001 for the Company, for the period
January 1, 2000 to March 13, 2000 for MEHC (Predecessor), for the period March
14, 2000 to December 31, 2000 for the Company, and for the year ended December
31, 1999 for MEHC (Predecessor), included in this prospectus and the related
financial statement schedules included elsewhere in the registration statement,
have been audited by Deloitte & Touche LLP, independent auditors, as stated in
their report appearing herein (which report expresses an unqualified opinion
and includes an explanatory paragraph referring to the Company's change in its
accounting policy for major maintenance, overhaul, and well workover costs), and
have been so included in reliance upon the report of such firm given upon their
authority as experts in accounting and auditing.

With respect to the unaudited interim financial information for the periods
ended September 30, 2002 and 2001, which is included in this prospectus,
Deloitte & Touche LLP have applied limited procedures in accordance with
professional standards for a review of such information. However, as stated in
their report included in the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2002 and included herein, they did not audit and
they do not express an opinion on that interim financial information.
Accordingly, the degree of reliance on their report on such information should
be restricted in light of the limited nature of the review procedures applied.
Deloitte & Touche LLP are not subject to the liability provisions of Section 11
of the Securities Act of 1933 for their report on the unaudited interim
financial information because this report is not a "report" or a "part" of the
registration statement prepared or certified by an accountant within the meaning
of Sections 7 and 11 of the Act.

WHERE YOU CAN FIND MORE INFORMATION

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

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

122

INDEX TO FINANCIAL STATEMENTS

PAGE

Independent Accountants' Report ........................................................ F-2

Consolidated Balance Sheets as of September 30, 2002 (unaudited)
and December 31, 2001 ................................................................ F-3

Unaudited Consolidated Statements of Operations for the three- and nine-month periods
ended September 30, 2002 and 2001 ..................................................... F-4

Unaudited Consolidated Statements of Cash Flows for the nine-month periods ended
September 30, 2002 and 2001 ........................................................... F-5

Notes to Unaudited Consolidated Financial Statements ................................... F-6

Independent Auditors' Report ........................................................... F-21

Consolidated Balance Sheets as of December 31, 2001 and 2000 ........................... F-22

Consolidated Statements of Operations for the year ended December 31, 2001 for the
Company, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor),
for the period March 14, 2000 to December 31, 2000 for the Company, and for the year
ended December 31, 1999 for MEHC (Predecessor) ........................................ F-23

Consolidated Statements of Stockholders' Equity for the year ended December 31, 2001 for
the Company, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor),
for the period March 14, 2000 to December 31, 2000 for the Company, and for the year
ended December 31, 1999 for MEHC (Predecessor) ........................................ F-24

Consolidated Statements of Cash Flows for the year ended December 31, 2001 for the
Company, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor),
for the period March 14, 2000 to December 31, 2000 for the Company, and for the year
ended December 31, 1999 for MEHC (Predecessor) ........................................ F-25

Notes to Consolidated Financial Statements ............................................. F-26

F-1

INDEPENDENT ACCOUNTANTS' REPORT

Board of Directors and Shareholders
MidAmerican Energy Holdings Company
Des Moines, Iowa

We have reviewed the accompanying consolidated balance sheet of MidAmerican
Energy Holdings Company and subsidiaries (the Company) as of September 30, 2002,
and the related consolidated statements of operations for the three-month and
nine-month periods ended September 30, 2002 and 2001, and the related
consolidated statements of cash flows for the nine-month periods ended September
30, 2002 and 2001. These financial statements are the responsibility of the
Company's management.

We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and of making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with auditing standards generally accepted in the United States of America, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should
be made to such consolidated financial statements for them to be in conformity
with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheet of
MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2001,
and the related consolidated statements of operations, shareholders' equity, and
cash flows for the year then ended (not presented herein); and in our report
dated January 17, 2002 (March 27, 2002 as to Notes 20.A. and 21 and August 2,
2002 as to Note 23), we expressed an unqualified opinion on those consolidated
financial statements. In our opinion, the information set forth in the
accompanying consolidated balance sheet as of December 31, 2001, is fairly
stated, in all material respects, in relation to the consolidated balance sheet
from which it has been derived.

DELOITTE & TOUCHE LLP
Des Moines, Iowa
November 8, 2002

F-2

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

AS OF
-------------------------------
SEPTEMBER 30, DECEMBER 31,
2002 2001
--------------- ---------------
(UNAUDITED)

ASSETS
Current assets:
Cash and cash equivalents ....................................................... $ 662,061 $ 386,745
Restricted cash and short-term investments ...................................... 56,466 30,565
Accounts receivable ............................................................. 549,656 310,030
Inventories ..................................................................... 132,153 135,822
Other current assets ............................................................ 187,773 106,124
----------- -----------
Total current assets .......................................................... 1,588,109 969,286

Property, plant, contracts and equipment, net .................................... 9,168,940 6,537,371
Excess of cost over fair value of net assets acquired, net ....................... 4,223,198 3,638,546
Regulatory assets ................................................................ 538,134 221,120
Other investments ................................................................ 444,183 174,185
Equity investments ............................................................... 274,198 261,432
Deferred charges and other assets ................................................ 747,288 824,712
----------- -----------
TOTAL ASSETS ..................................................................... $16,984,050 $12,626,652
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
LIABILITIES:
Current liabilities:
Accounts payable ................................................................ $ 381,983 $ 266,027
Accrued interest ................................................................ 201,082 130,569
Accrued taxes ................................................................... 93,028 88,973
Other accrued liabilities ....................................................... 525,750 308,924
Short-term debt ................................................................. 642,031 256,012
Current portion of long-term debt ............................................... 483,106 317,180
----------- -----------
Total current liabilities ..................................................... 2,326,980 1,367,685
Other long-term accrued liabilities .............................................. 612,321 537,495
Parent company debt .............................................................. 1,623,178 1,834,498
Subsidiary and project debt ...................................................... 6,388,169 4,754,811
Deferred income taxes ............................................................ 1,297,136 1,284,268
----------- -----------
TOTAL LIABILITIES ................................................................ 12,247,784 9,778,757
----------- -----------
Deferred income .................................................................. 82,305 85,917
Minority interest ................................................................ 6,012 44,477
Preferred securities of subsidiaries ............................................. 93,619 121,183
Company-obligated mandatorily redeemable preferred securities of subsidiary
trusts .......................................................................... 2,062,815 788,151
Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary
trusts .......................................................................... -- 100,000

Commitments and contingencies (Note 12)

SHAREHOLDERS' EQUITY:
Zero coupon convertible preferred stock -- authorized 50,000 shares, no par value,
41,263 and 34,563 shares issued and outstanding at September 30, 2002, and
December 31, 2001, respectively ................................................. -- --
Common stock -- authorized 60,000 shares, no par value, 9,281 shares issued and
outstanding ..................................................................... -- --
Additional paid-in capital ....................................................... 1,956,509 1,553,073
Retained earnings ................................................................ 510,766 223,926
Accumulated other comprehensive income (loss) .................................... 24,240 (68,832)
----------- -----------
TOTAL SHAREHOLDERS' EQUITY ....................................................... 2,491,515 1,708,167
----------- -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ....................................... $16,984,050 $12,626,652
=========== ===========

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

F-3

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
(UNAUDITED)

THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
------------------------------ -----------------------------
2002 2001 2002 2001
-------------- ------------- ------------- -------------

REVENUES:
Operating revenue ........................... $ 1,238,463 $1,076,786 $3,404,533 $3,756,931
Income on equity investments ................ 10,939 6,332 29,863 23,622
Interest and other income ................... 32,714 223,941 115,348 262,522
----------- ---------- ---------- ----------
TOTAL REVENUES ............................... 1,282,116 1,307,059 3,549,744 4,043,075
----------- ---------- ---------- ----------
COSTS AND EXPENSES:
Cost of sales ............................... 443,144 472,964 1,283,238 2,010,164
Operating expense ........................... 343,303 293,867 948,913 844,776
Depreciation and amortization ............... 129,362 122,686 386,531 395,253
Interest expense ............................ 168,450 119,809 462,998 362,163
Less interest capitalized ................... (9,152) (19,877) (24,128) (72,010)
----------- ---------- ---------- ----------
TOTAL COSTS AND EXPENSES ..................... 1,075,107 989,449 3,057,552 3,540,346
----------- ---------- ---------- ----------
Income before provision for income taxes ..... 207,009 317,610 492,192 502,729

Provision for income taxes ................... 26,788 241,873 80,226 296,088
----------- ---------- ---------- ----------
Income before minority interest .............. 180,221 75,737 411,966 206,641

Minority interest ............................ 45,344 27,796 105,166 79,952
----------- ---------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE ..................... 134,877 47,941 306,800 126,689

Cumulative effect of change in accounting
principle, net of tax ....................... -- -- -- (4,604)
----------- ---------- ---------- ----------
NET INCOME AVAILABLE TO COMMON AND
PREFERRED SHAREHOLDERS ...................... $ 134,877 $ 47,941 $ 306,800 $ 122,085
=========== ========== ========== ==========

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

F-4

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)

NINE MONTHS ENDED SEPTEMBER 30
------------------------------
2002 2001
--------------- -------------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................................... $ 306,800 $ 122,085
Adjustments to reconcile to net cash flows from operating activities:
Cumulative effect of change in accounting principle, net of tax .......... -- 4,604
Gains on disposals ....................................................... (57,480) (221,108)
Depreciation and amortization ............................................ 386,531 282,125
Amortization of excess of cost over fair value of net assets acquired .... -- 74,728
Amortization of deferred financing costs and other costs ................. 32,589 15,542
Provision for deferred income taxes ...................................... 40,518 236,901
Undistributed earnings on equity investments ............................. (14,828) (23,622)
Changes in other items:
Accounts receivable ..................................................... (76,621) 607,287
Other current assets .................................................... 47,493 23,381
Accounts payable and accrued liabilities ................................ (15,193) (389,295)
Accrued interest ........................................................ 79,548 78,391
Accrued taxes ........................................................... (43,963) (25,733)
Deferred income ......................................................... (2,612) 5,704
------------ ----------
NET CASH FLOWS FROM OPERATING ACTIVITIES ................................. 682,782 790,990
------------ ----------

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of Kern River, net of cash acquired .......................... (419,724) --
Acquisition of Northern Natural Gas, net of cash acquired ................ (899,249) --
Acquisition of Yorkshire Electricity, net of cash acquired ............... (8,380) (36,860)
Proceeds from sale of Northern Supply .................................... -- 377,396
Purchase of convertible preferred securities ............................. (275,000) --
Capital expenditures relating to operating projects ...................... (328,544) (242,337)
Construction and other development costs ................................. (450,206) (134,625)
Receipt of liquidated damages on construction projects ................... -- 29,648
Proceeds from sale of assets ............................................. 210,767 10,500
Purchase of minority interests ........................................... (33,262) (29,276)
Acquisition of realty companies, net of cash acquired .................... (102,699) (32,565)
Change in restricted investments ......................................... 16,746 17,924
Change in other assets ................................................... 25,895 (8,502)
------------ ----------
NET CASH FLOWS FROM INVESTING ACTIVITIES ................................. (2,263,656) (48,697)
------------ ----------

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of convertible preferred stock .................... 402,000 --
Proceeds from issuance of trust preferred securities ..................... 1,273,000 --
Net repayment of short-term subsidiary debt .............................. (77,585) (160,288)
Net proceeds from short-term parent company debt ......................... 13,500 64,500
Repayment of subsidiary and project debt ................................. (377,644) (278,867)
Proceeds from subsidiary and project debt ................................ 780,142 200,000
Redemption of preferred securities of subsidiaries ....................... (127,613) (14,616)
Change in restricted investments-debt service ............................ (25,901) (6,585)
Other .................................................................... (44,999) (2,105)
------------ ----------
NET CASH FLOWS FROM FINANCING ACTIVITIES ................................. 1,814,900 (197,961)
------------ ----------
Effect of exchange rate changes on cash .................................. 41,290 1,689
------------ ----------
Net increase in cash and cash equivalents ................................ 275,316 546,021
Cash and cash equivalents at beginning of period ......................... 386,745 38,152
------------ ----------
Cash and cash equivalents at end of period ............................... $ 662,061 $ 584,173
============ ==========
Interest paid, net of amount capitalized ................................. $ 404,288 $ 222,991
============ ==========
Income taxes paid ........................................................ $ 55,437 $ 43,632
============ ==========

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

F-5

MIDAMERICAN ENERGY HOLDINGS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

In the opinion of management of MidAmerican Energy Holdings Company and
subsidiaries (the "Company"), the accompanying unaudited consolidated financial
statements contain all adjustments (consisting of normal recurring accruals)
necessary to present fairly the financial position as of September 30, 2002, and
the results of operations for the three months and nine months ended September
30, 2002 and 2001 and the related consolidated statements of cash flows for the
nine months ended September 30, 2002 and 2001. The results of operations for the
three months and nine months ended September 30, 2002 and 2001 are not
necessarily indicative of the results to be expected for the full year.

The consolidated financial statements include the accounts of MidAmerican Energy
Holdings Company and its wholly and majority owned subsidiaries. Other
investments and corporate joint ventures, where the Company has the ability to
exercise significant influence, are accounted for under the equity method.
Investments where the Company's ability to influence is limited are accounted
for under the cost method of accounting.

Certain amounts in the 2001 financial statements and supporting note disclosures
have been reclassified to conform to the 2002 presentation. Such
reclassification did not impact previously reported net income or retained
earnings.

Although the Company believes that the disclosures are adequate to make the
information presented not misleading, it is suggested that these financial
statements be read in conjunction with the consolidated financial statements and
the notes thereto included in the Company's latest Annual Report on Form 10-K.

2. ACQUISITIONS

Kern River

On March 27, 2002, the Company closed on a definitive agreement with The
Williams Companies, Inc. ("Williams") to acquire Williams" Kern River Gas
Transmission Company ("Kern River"), a 926-mile interstate pipeline transporting
Rocky Mountain and Canadian natural gas to markets in California, Nevada and
Utah.

The Kern River pipeline is an important route for the transmission of natural
gas from the vast reserves in the Rocky Mountain states to the rapidly growing
markets in Utah, Nevada and California. Constructed in 1992, the Kern River
pipeline extends from Opal, Wyoming, to the San Joaquin Valley near Bakersfield,
California, and has a design capacity of 845 million cubic feet per day.

The Company paid $419.7 million, net of cash acquired of $7.7 million and
transaction costs and working capital adjustments, for Kern River's gas pipeline
business. At the time of the acquisition, Kern River had $505 million of
indebtedness, the unamortized portion of which remains outstanding. The
acquisition has been accounted for as a purchase business combination. The
Company is in the process of completing the allocation of the purchase price to
the assets and liabilities acquired. The results of operations for Kern River
are included in the Company's results beginning March 27, 2002.

The recognition of excess of cost over fair value of net assets acquired
resulted from various attributes of Kern River's operations and business in
general. These attributes include, but are not limited to:

o Opportunities for expansion;

o High credit quality shippers contracting with Kern River;

o Kern River's strong competitive position;

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

F-6

o Strong demand for gas in the Western markets; and

o An ample supply of low-cost gas.

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

Northern Natural Gas Company

On August 16, 2002, the Company closed on a definitive agreement with Dynegy
Inc. ("Dynegy") to acquire Dynegy's Northern Natural Gas Company ("Northern
Natural Gas"), a 16,600-mile interstate pipeline extending from southwest Texas
to the upper Midwest region of the United States.

With a design capacity of 4.4 billion cubic feet of natural gas per day,
Northern Natural Gas accesses natural gas supply from many of the larger
producing regions in North America including the Rocky Mountains, Hugoton,
Permian, Anadarko and Western Canadian basins. The system provides
transportation and storage services to approximately 70 utility customers and
numerous industrial customers in the Upper Midwest.

Northern Natural Gas also provides cross-haul and grid transportation between
other interstate and intrastate pipelines in Permian, Anadarko, Hugoton and
Midwest areas. It operates three natural gas storage facilities and two
liquefied natural gas peaking units for a total storage capacity of 59 billion
cubic feet and peak delivery capability of over 1.3 billion cubic feet of
natural gas per day.

The Company paid $899.2 million for Northern Natural Gas, net of cash acquired
of $1.4 million and transaction costs and working capital adjustments. At the
time of the acquisition, Northern Natural Gas had $950 million of debt
outstanding. The acquisition has been accounted for as a purchase business
combination. The Company is in the process of completing the working capital
negotiations and the allocation of the purchase price to the assets and
liabilities acquired. The results of operations for Northern Natural Gas are
included in the Company's results beginning August 16, 2002.

The recognition of excess of cost over fair value of net assets acquired
resulted from various attributes of Northern Natural Gas' operations and
business in general. These attributes include, but are not limited to:

o High credit quality shippers contracting with Northern Natural Gas;

o Northern Natural Gas' strong competitive position;

o Strategic location in the high demand Upper Midwest markets;

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

o Exceptional operating track record; and

o Opportunities for expansion.

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

The following pro forma financial information of the Company represents the
unaudited pro forma results of operations as if the Kern River and Northern
Natural Gas acquisitions, the related financings and the Yorkshire Swap, as
described in Note 3 of Notes to Consolidated Financial Statements in the Annual
Report on Form 10-K for the year ended December 31, 2001, had occurred at the
beginning of each year. These pro forma results have been prepared for
comparative purposes only and do not profess to be indicative of the results of
operations which would have been achieved had these transactions been completed
at the beginning of each year, nor are the results indicative of the Company's
future results of operations (in thousands).

F-7

THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
--------------------------- ---------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------

Revenue .................................... $1,204,513 $1,050,104 $3,888,873 $3,849,034
Income before cumulative effect of change in
accounting principle ...................... 126,389 71,421 310,359 185,154
Net income available to common and preferred
shareholders .............................. 126,389 71,421 310,359 180,550

3. CALENERGY GAS DISPOSAL

In May 2002, CalEnergy Gas, an indirect wholly owned subsidiary of the Company,
executed the sale of several of its U.K. natural gas assets to Gaz de France for
(pounds sterling)137.0 million (approximately $200 million). CalEnergy Gas sold
four natural gas-producing fields located in the southern basin of the U.K.
North Sea, including Anglia, Johnston, Schooner and Windermere. The transaction
also included the sale of rights in four gas fields (in development/
construction) and three exploration blocks owned by CalEnergy Gas. As a result
of the sale, the Company's nine month results ending September 30, 2002 include
pre-tax and after-tax income of $54.3 million and $41.3 million, respectively,
which includes a write off of non-deductible goodwill of $49.6 million. The
three month results ending September 30, 2002 include $21.1 million in tax
benefits related to the sale.

4. PROPERTY, PLANT, CONTRACTS AND EQUIPMENT, NET

Property, plant, contracts and equipment, net comprise the following (in
thousands):

SEPTEMBER 30, DECEMBER 31,
2002 2001
--------------- ---------------

Operating assets:
Utility generation, distribution and transmission systems .......... $ 10,102,855 $ 7,574,339
Independent power plants ........................................... 1,406,345 1,402,102
Utility non-operational assets ..................................... 363,910 354,366
Power sales agreements ............................................. 19,185 48,185
Realty company assets .............................................. 73,785 51,150
Other assets ....................................................... 54,197 53,876
------------ ------------
Total operating assets ............................................. 12,020,277 9,484,018
Less accumulated depreciation and amortization ..................... (3,995,916) (3,650,875)
------------ ------------
Net operating assets ............................................... 8,024,361 5,833,143
Mineral and gas reserves and exploration assets, net ............... 280,722 387,697
Construction in progress:
Zinc Recovery Project ............................................. 213,923 163,366
Utility generation, distribution and transmission systems ......... 253,945 149,225
Kern River natural gas pipeline expansion ......................... 389,321 --
Other ............................................................. 6,668 3,940
------------ ------------
Total .......................................................... $ 9,168,940 $ 6,537,371
============ ============

Zinc Recovery Project

CalEnergy Minerals, LLC, an indirect wholly owned subsidiary of the Company, is
constructing the Zinc Recovery Project. The Zinc Recovery Project is designed to
have a capacity of approximately 30,000 metric tons per year and is scheduled to
commence commercial operations in 2002. Total project costs of the Zinc Recovery
Project are expected to be approximately $244 million, net of damages received
from Kvaerner, which is being funded by $140.5 million of debt and the balance
from funds provided by the parent company. The Zinc Recovery Project has
incurred $213.9 million, net of damages, of such costs through September 30,
2002.

F-8

Utility generation, distribution and transmission systems

Through 2007, MidAmerican Energy plans to develop and construct two electric
generating plants in Iowa. MidAmerican Energy expects to invest approximately
$1.2 billion in the two plants, including the cost of related transmission
facilities and allowance for funds used during construction. The two plants may
provide approximately 950 megawatts of generating capacity for MidAmerican
Energy depending on management's on-going assessment of needs and related
factors.

The first project is a 500-megawatt (based on expected accreditation) natural
gas-fired combined cycle unit with an estimated cost of $415 million.
MidAmerican Energy will own 100% of the plant and operate it. MidAmerican Energy
has received a certificate from the Iowa Utilities Board allowing it to
construct the plant. Also, on May 29, 2002, the Iowa Utilities Board issued an
order that provides the ratemaking principles for the gas-fired plant, thus
limiting the regulatory risk of constructing the plant. As a result of that
order, MidAmerican Energy is proceeding with the construction of the plant. It
is anticipated that the first phase of the project will be completed in 2003,
resulting in an additional 310 megawatts of accredited capacity, with the
remainder being completed in 2005.

Kern River natural gas pipeline expansion

On July 17, 2002, Kern River received approval from FERC to construct, own and
operate a major expansion to its pipeline system (the "2003 Expansion Project").
The 2003 Expansion Project will loop most of Kern River's existing mainline,
construct three new compressor stations and upgrade or modify Kern River's six
existing compressor stations. The 2003 Expansion Project, which is expected to
be completed and operational by May 2003, will increase Kern River's capacity by
approximately 900 MMcf per day. Service will be provided under long-term
contracts subject to incremental rates. The estimated cost of the expansion is
approximately $1.2 billion.

5. OTHER INVESTMENTS

On March 27, 2002, the Company invested $275.0 million in Williams in exchange
for shares of 9 7/8 percent cumulative convertible preferred stock of Williams.
Dividends are scheduled to be received quarterly, which commenced July 1, 2002.
This investment is accounted for under the cost method. The Company is aware
that there have been public announcements that Williams' financial condition has
deteriorated as a result of reduced liquidity. Williams' senior unsecured debt
obligations are currently rated B1 by Moody's, B by Standard & Poor's and B- by
Fitch. The Company has not recorded an impairment on this investment as of
September 30, 2002, and is monitoring the situation.

In connection with this investment, the Company issued $275.0 million of no par,
zero coupon convertible preferred stock to Berkshire Hathaway. Each share of
preferred stock is convertible at the option of the holder into one share of the
Company's common stock subject to certain adjustments as described in the
Company's Amended and Restated Articles of Incorporation.

6. TEESSIDE POWER LIMITED RESTRUCTURING

CE Electric UK Funding, an indirect wholly owned subsidiary of the Company, has
a 15.4% interest in Teesside Power Limited ("TPL"). TPL owns and operates an
1,875MW combined cycle gas-fired power plant. Shareholders in TPL had previously
utilized TPL's taxable losses with an obligation to reimburse TPL later in the
project's life. In May 2002, TPL executed a restructuring and stabilization
agreement with its lenders. The contract included an agreement between TPL and
its shareholders with respect to the waiver of these repayment obligations. In
May 2002, CE Electric UK Funding released $35.7 million due to the repayment
obligation being waived which is reflected as a current tax benefit in the
provision for income taxes.

7. REAL ESTATE COMPANY ACQUISITIONS

During 2002, HomeServices separately acquired three real estate companies for an
aggregate purchase price of approximately $100 million, net of cash acquired,
plus working capital and certain other adjustments. For the year ended December
31, 2001, these real estate companies had combined revenue

F-9

of approximately $356 million on 42,000 closed sides representing $13.7 billion
of sales volume. Additionally, HomeServices is obligated to pay a maximum
earnout of $18.5 million calculated based on 2002 financial performance
measures. These purchases were financed using HomeServices' $65 million
revolving credit facility and MidAmerican Energy Holdings Company's corporate
revolver for $40 million, which was contributed to HomeServices as equity. The
Company is in the process of completing the allocation of the purchase price to
the assets and liabilities acquired.

8. DEBT ISSUANCES AND REDEMPTIONS

On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% notes due
in 2031. The proceeds are being used to refinance existing debt and preferred
securities and for other corporate purposes. On March 11, 2002, MidAmerican
Energy redeemed all $100 million of its 7.98% MidAmerican-obligated preferred
securities of subsidiary trust at 100% of the principal amount plus accrued
interest.

On May 1, 2002, MidAmerican Energy reacquired all $26.7 million of its $7.80
series of preferred securities. The first $13.3 million of preferred securities
were redeemed at 100% of the principal amount plus accrued dividends, and the
remaining $13.4 million was redeemed at 103.9% of the principal amount plus
accrued dividends.

On June 21, 2002, Kern River closed on a bank loan facility providing for
aggregate loans of up to $875 million to be used for the construction of the
Kern River 2003 Expansion Project. The facility, which matures 15 years after
the 2003 Expansion Project commences operation, has a variable interest rate
which increases over the term of the facility from 1.375% to 4.5% over LIBOR.
Kern River has drawn $384.9 million on this facility as of September 30, 2002.

9. ACCOUNTING POLICY CHANGE

Effective January 1, 2001, the Company changed its accounting policy regarding
major maintenance and repairs for nonregulated gas projects, nonregulated plant
overhaul costs and geothermal well rework costs to the direct expense method
from the former policy of monthly accruals based on long-term scheduled
maintenance plans for the gas projects and deferral and amortization of plant
overhaul costs and geothermal well rework costs over the estimated useful lives.
The cumulative effect of the change in accounting principle for 2001 was $4.6
million, net of taxes of $.7 million.

10. ACCOUNTING PRONOUNCEMENTS AND REPORTING ISSUES

On January 1, 2002, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets," which
dictates the accounting for acquired goodwill and other intangible assets. SFAS
No. 142 requires that amortization of goodwill and indefinite-lived intangible
assets be discontinued and that entities disclose net income for prior periods
adjusted to exclude such amortization and related income tax effects, as well as
a reconciliation from the originally reported net income to the adjusted net
income. The Company's related amortization consists of goodwill amortization and
the related income tax effect. Following is a reconciliation of net income as
originally reported for the periods ended September 30, 2002 and 2001, to
adjusted net income (in thousands):

THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
-------------------------- --------------------------
2002 2001 2002 2001
------------ ----------- ----------- ------------

Net income as originally reported ......... $ 134,877 $ 47,941 $306,800 $ 122,085
Goodwill amortization ..................... -- 24,739 -- 74,728
Income tax benefit ........................ -- (503) -- (1,504)
--------- -------- -------- ---------
Net income as adjusted .................... $ 134,877 $ 72,177 $306,800 $ 195,309
========= ======== ======== =========

In accordance with SFAS No. 142, the Company has determined its reporting units
and has completed the initial impairment testing of goodwill primarily using a
discounted cash flow methodology. No impairment was indicated as a result of the
initial impairment testing. See Note 14 for allocation of goodwill to reporting
units.

F-10

In August 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires
recognition on the balance sheet of legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction,
development and/or normal operation of such assets. Additionally, at the time an
asset retirement obligation (ARO) is recognized, an ARO asset of the same amount
is recorded and depreciated. This pronouncement is effective for fiscal years
beginning after June 15, 2002. The Company is evaluating the impact that
adoption of this standard will have on its consolidated financial statements.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets", which addresses the financial accounting and
reporting for the impairment or disposal of long-lived assets. The adoption of
SFAS No. 144 on January 1, 2002, did not have any impact on the Company's
consolidated financial statements.

The Emerging Issues Task Force (EITF) recently issued EITF Issue No. 02-3,
"Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under
Issues No. 98-10 and 00-17." In accordance with EITF No. 02-3, all gains and
losses on energy trading contracts must be reported net on the income statement,
effective for reporting periods ending after July 15, 2002, with all prior
periods presented being reclassified to a consistent presentation. MidAmerican
Energy's nonregulated wholesale gas and electric marketing activities qualify as
"energy trading" contracts under the guidance of EITF No. 98-10. In accordance
with EITF Issue No. 02-3, effective September 30, 2002, for MidAmerican Energy,
all trading revenues are reported net of the cost of such sales. Previously,
such amounts were recorded gross. All prior periods have been reclassified to
conform to the net presentation.

11. COMPREHENSIVE INCOME

The differences from net income to total comprehensive income for the Company
are due to foreign currency translation adjustments, unrealized holding gains
and losses of marketable securities during the periods, and the effective
portion of net gains and losses of derivative instruments classified as cash
flow hedges. Total comprehensive income for the nine months ended September 30,
2001, includes a transition loss of $3.3 million related to the initial adoption
of SFAS No. 133. Total comprehensive income for the Company is shown in the
table below (in thousands).

THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
------------------------- --------------------------
2002 2001 2002 2001
----------- ----------- ----------- ------------

Net income ................................. $134,877 $ 47,941 $ 306,800 $ 122,085
Other comprehensive income --
Foreign currency translation .............. 39,437 31,791 120,905 (16,681)
Marketable securities, net of tax ......... 332 (7,683) (3,337) (5,816)
Cash flow hedges, net of tax .............. (3,694) (3,897) (24,496) 32,598
-------- -------- --------- ---------
Total comprehensive income ................. $170,952 $ 68,152 $ 399,872 $ 132,186
======== ======== ========= =========

12. COMMITMENTS AND CONTINGENCIES

A. FINANCIAL CONDITION OF EDISON

Southern California Edison Company ("Edison"), a wholly owned subsidiary of
Edison International, is a public utility primarily engaged in the business of
supplying electric energy to retail customers in Central and Southern
California, excluding Los Angeles. Due to reduced liquidity, Edison failed to
pay approximately $119 million due under the power purchase agreement with CE
Generation affiliates for power delivered in the fourth quarter 2000 and the
first quarter 2001. Due to Edison's failure to pay contractual obligations, the
CE Generation affiliates had established an allowance for doubtful accounts of
approximately $21 million as of December 31, 2001. The final payment of the past
due amounts was received from Edison on March 1, 2002. Following the receipt of
Edison's payment of past due balances, the CE Generation affiliates released the
remaining allowance for doubtful accounts.

F-11

B. CASECNAN CONSTRUCTION ARBITRATION

On May 7, 1997, CE Casecnan entered into a fixed-price, date certain, turnkey
engineering, procurement and construction contract to complete the construction
of the Casecnan Project (the "Construction Contract"). The work under the
Construction Contract was conducted by a consortium consisting of Cooperativa
Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., working
together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power
Engineering Ltd. (collectively, the "Contractor").

On November 20, 1999, the Construction Contract was amended to extend the
Guaranteed Substantial Completion Date for the Casecnan Project to March 31,
2001. This amendment was approved by the lenders" independent engineer under the
Casecnan Indenture. In January 2001, CE Casecnan received a new working schedule
from the Contractor that showed a completion date of August 31, 2001. The delay
in completion was attributable in part to the collapse in December 2000 of the
Casecnan Project's partially completed vertical surge shaft and the need to
drill a replacement surge shaft.

Upon receipt of the working schedule, CE Casecnan sought and obtained from the
lender's independent engineer approval for a revised construction schedule under
the Casecnan Indenture. In connection with the revised schedule, MidAmerican
Energy Holdings Company agreed to make available up to $11.6 million of
additional funds under certain conditions pursuant to a Shareholder Support
Letter dated February 8, 2001 (Shareholder Support Letter). MidAmerican Energy
Holdings Company has fully satisfied its obligations under the Shareholder
Support Letter.

The receipt of the new working schedule did not change the Guaranteed
Substantial Completion Date under the Construction Contract, and the Contractor
was still contractually obligated either to complete the Casecnan Project by
March 31, 2001, or to pay liquidated damages for the delay in completion. The
Casecnan Project entered into commercial operations on December 11, 2001. In
2002, CE Casecnan has received approximately $6.0 million of liquidated damages
from demands made on the demand guarantees posted by Commerzbank on behalf of
the Contractor.

On February 12, 2001, the Contractor filed a Request for Arbitration with the
International Chamber of Commerce seeking an extension of the Guaranteed
Substantial Completion Date by up to 153 days through August 31, 2001, resulting
from various alleged force majeure events. In its March 20, 2001, Supplement to
Request for Arbitration, the Contractor requested compensation for alleged
additional costs of approximately $4 million it incurred from the claimed force
majeure events to the extent it is unable to recover from its insurer. On April
20, 2001, the Contractor filed a further supplement seeking an additional
compensation for damages of approximately $62 million for the alleged force
majeure event (and geologic conditions) related to the collapse of the surge
shaft. The Contractor has alleged that the circumstances surrounding the placing
of the Casecnan Project into commercial operation on December 11, 2001, amounted
to a repudiation of the Construction Contract and has filed a claim for
unspecified quantum meruit damages. The Contractor also has alleged that the
delay liquidated damages clause in the EPC Contract is unenforceable as a
penalty. CE Casecnan believes all such allegations and claims are without merit
and is vigorously contesting the Contractor's claims. The arbitration is being
conducted applying New York law and in accordance with the rules of the
International Chamber of Commerce. Although the outcome of the arbitration, as
with any litigious proceedings, is difficult to access, CE Casecnan believes it
will prevail and receive additional liquidated damages in the arbitration.

On June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from
making calls on the demand guaranty posted by Banca di Roma in support of the
Contractor's obligations to CE Casecnan for delay liquidated damages. On April
26, 2002, CE Casecnan and the Contractor mutually agreed that no demands would
be made on the Banca di Roma demand guaranty except pursuant to a final
arbitration award. Hearings on the force majeure claims were held in London from
July 2 to 14, 2001, and hearings on the Contractor's April 20, 2001, supplement
were held from September 24 to October 3, 2001. Further hearings were held from
January 21 to February 1, 2002 and from March 14 to 19, 2002. From November 4 to
6, 2002, hearings were held on the Contractor's claim with respect to the
alleged unenforceability of the delay liquidated damages clause. On November 7,
2002, the International Chamber of Commerce issued the arbitration tribunal's
partial award with respect to the Contractor's force majeure and geologic

F-12

conditions claims. The arbitral panel awarded the Contractor 18 days of schedule
relief in the aggregate for all of the force majeure events and awarded the
Contractor $3.8 million with respect to the cost of the collapsed surge shaft.
All of the Contractor's other claims that have been heard by the arbitral
tribunal were denied.

Further hearings on the Contractor's repudiation and quantum meruit claims are
scheduled for January 20 to 23 and 28 to 31, 2003. These claims, and the alleged
unenforceability of the delay liquidated damages clause, have not been ruled on
by the arbitration tribunal.

C. CASECNAN SHAREHOLDER ISSUE

Pursuant to the share ownership adjustment mechanism in the Casecnan Shareholder
Agreement, which is based upon pro forma financial projections of the Casecnan
Project prepared following commencement of commercial operations, the Company,
through its indirect wholly owned subsidiary CE Casecnan Ltd., has advised the
minority shareholder LaPrairie Group Contractors (International) Ltd. ("LPG"),
that the Company's ownership interest in CE Casecnan will increase to 100%. On
July 8, 2002, LPG filed a complaint in the Superior Court of the State of
California, City and County of San Francisco against, inter alia, CE Casecnan
Ltd. and MidAmerican Energy Holdings Company. In the complaint, LPG seeks
compensatory and punitive damages for alleged breaches of the Shareholder
Agreement and alleged breaches of fiduciary duties allegedly owed by the Company
and CE Casecnan Ltd. to LPG. The complaint also seeks injunctive relief against
all defendants and a declaratory judgment that LPG is entitled to maintain its
15% interest in Casecnan. The impact, if any, of this litigation on the Company
cannot be determined at this time.

D. CASECNAN NIA ARBITRATION

In August 2002, CE Casecnan commenced arbitration against the National
Irrigation Administration ("NIA") in connection with the Casecnan Project by
serving it with a Request for Arbitration under International Chamber of
Commerce rules (the "Request for Arbitration"). In the Request for Arbitration,
CE Casecnan claimed that NIA has breached its obligations under the Casecnan
Project Agreement by failing to reimburse CE Casecnan for certain tax payments
and by failing to pay the portion of the Water Delivery Fee under the Casecnan
Project Agreement attributable to certain tax payments. The Casecnan Project
Agreement provides for arbitration in accordance with International Chamber of
Commerce rules by a panel of three arbitrators in Singapore. CE Casecnan is
awaiting NIA's formal answer to the Request for Arbitration. CE Casecnan intends
to vigorously pursue its claims in these proceedings.

E. MALITBOG ARBITRATION

VGPC and PNOC-EDC have been negotiating with respect to certain disputes
concerning the Malitbog energy conversion agreement ("ECA") but have been unable
to reach a mutually acceptable resolution. Accordingly, on October 16, 2000,
VGPC commenced arbitration against PNOC-EDC by serving it with a Notice of
Arbitration and Statement of Claim (the "Notice of Arbitration"). In the Notice
of Arbitration, VGPC claimed that PNOC-EDC breached the Malitbog ECA by
improperly characterizing certain No Fault Outages as Forced Outage Hours and
then deducting them from the total number of hours each month. On December 22,
2000, VGPC filed an Amended Statement of Claim pursuant to which VGPC added a
claim that PNOC-EDC breached the Malitbog ECA by refusing to accept VGPC's
specified Nominated Capacity for contract years July 25, 1999 to July 25, 2000,
and July 25, 2000 to July 25, 2001. A Second Amended Statement of Claim was
filed on March 9, 2001, to add the Scheduled Maintenance issue. VGPC is
vigorously pursuing its claims in this proceeding. Hearings were conducted from
June 24, 2002, to July 5, 2002, in Sydney, Australia, and the Company expects a
ruling on these hearings in the fourth quarter of 2002.

F. MAHANAGDONG ARBITRATION

On September 25, 2002, CE Luzon Geothermal Power Company, Inc. ("CE Luzon"), an
indirect majority owned subsidiary of the Company, commenced arbitration against
PNOC-EDC by serving it with a

F-13

Request for Arbitration (the "Request for Arbitration") under International
Chamber of Commerce rules. In the Request for Arbitration, CE Luzon claimed that
PNOC-EDC breached the Mahanagdong ECA by refusing to accept CE Luzon's specified
Nominated Capacity for contract years July 25, 2001 to July 25, 2002 and July
25, 2002 to July 25, 2003. CE Luzon is awaiting PNOC-EDC's formal answer. CE
Luzon intends to vigorously pursue its claims in these proceedings.

G. REGULATORY ENVIRONMENT: PHILIPPINES

The Philippine Congress has passed the Electric Power Industry Reform Act of
2001, which is aimed at restructuring the Philippine power industry,
privatization of the NPC and introduction of a competitive electricity market,
among other initiatives. The implementation of the bill may have an impact on
the Company's future operations and the industry as a whole, the effect of which
is not yet determinable and estimable.

In connection with an interagency review of approximately 40 independent power
project contracts in the Philippines, the Casecnan Project (along with four
other unrelated projects) has reportedly been identified as raising legal and
financial questions and, with those projects, has been prioritized for
renegotiation. The Company's subsidiaries' Upper Mahiao, Malitbog, and
Mahanagdong projects, which, together with the Casecnan Project, collectively
the "Philippine Projects", have also reportedly been identified as raising
financial questions. No written report has yet been issued with respect to the
interagency review, and the timing and nature of steps, if any, that the
Philippine Government may take in this regard are not known. To the extent
disputes arise under the Philippine Projects' agreements with respect to the
Philippines Projects' obligations, rights and remedies thereunder, such disputes
will be determined by international arbitration in a neutral forum conducted in
accordance with the rules of the International Chamber of Commerce or UNCITRAL,
as applicable.

Representatives of CE Casecnan Water and Energy Company, Inc. ("CE Casecnan"), a
Philippine corporation, together with certain current and former Philippine
government officials, also have been requested to appear, and have appeared,
before a Philippine Senate committee which has independently raised questions
and made allegations with respect to the Casecnan Project's tariff structure and
implementation. No further hearings are scheduled at this time. CE Casecnan has
and intends to continue to respond to such questions and to vigorously defend
the Casecnan Project against any allegations, which may be made. CE Casecnan
believes the allegations made with respect to the Casecnan Project to be without
merit.

H. COOPER LITIGATION

On July 23, 1997, Nebraska Public Power District ("NPPD") filed a complaint, in
the United States District Court for the District of Nebraska, naming
MidAmerican Energy as the defendant and seeking declaratory judgment as to
issues under the parties' long-term power purchase agreement for Cooper Nuclear
Station ("Cooper") capacity and energy.

On July 31, 2002, MidAmerican Energy and NPPD signed an agreement on the
restructuring of the power purchase contract for Cooper. Under the terms of the
restructured contract, MidAmerican Energy will pay NPPD through December 31,
2004, a scheduled amount per unit for 380 megawatts of the accredited capacity
of Cooper and a minimum of approximately 1.2 million megawatt-hours (MWh) in the
last five months of 2002 and approximately 2.5 million MWh in each of 2003 and
2004. NPPD also paid MidAmerican Energy $39.1 million on August 1, 2002.

In December 2000, MidAmerican Energy ceased contributing decommissioning funds
to NPPD and maintained a separate fund for estimated Cooper decommissioning
costs. At the date of the contract restructuring, $18.3 million had been accrued
and retained by MidAmerican Energy in this separate fund. In conjunction with
the power purchase contract restructuring, MidAmerican Energy is recognizing the
$39.1 million cash payment and the $18.3 million previously accrued for
decommissioning into income based on the estimated energy expected to be
received for the remainder of the contract.

F-14

Finally, both parties agreed to release each other from any and all claims, past
or present, each might have under the power purchase contract prior to being
restructured and file to dismiss the litigation currently pending in U.S.
District Court.

Under the terms of MidAmerican Energy's power purchase contract with NPPD prior
to its restructuring, MidAmerican Energy paid NPPD one-half of the fixed and
operating costs of Cooper, excluding depreciation but including debt service,
and MidAmerican Energy's share of the nuclear fuel cost, including Department of
Energy disposal fees, based on energy delivered. In addition, prior to December
2000, MidAmerican Energy contributed toward payment of one-half of Cooper's
project decommissioning costs based on an assumed 2004 shutdown of the plant.

I. KVAERNER ARBITRATION

The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc.
("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering,
procure, construct and manage contract (the "Zinc Recovery Project EPC
Contract"). On June 14, 2001, CalEnergy Minerals, LLC issued notices of default,
termination and demand for payment of damages to Kvaerner under the Zinc
Recovery Project EPC Contract due to failure to meet performance obligations. As
a result of Kvaerner's failure to pay monetary obligations under the Zinc
Recovery Project EPC Contract, CalEnergy Minerals, LLC drew $29.6 million under
the EPC Contract Letter of Credit ("LOC") on July 20, 2001, and claimed the
retainage and balance of the contract price. The LOC draw, retainage and balance
of the contract price have been accounted for as a reduction of the capitalized
costs of the project. CalEnergy Minerals, LLC has entered into a time and
materials reimbursable engineer, procure and construction management contract
with AMEC E&C Services, Inc. to complete the Zinc Recovery Project.

On May 23, 2002, following various discussions and legal filings, CalEnergy
Minerals, LLC and Kvaerner entered into a Settlement Agreement. Under the terms
of the agreement, CalEnergy Minerals, LLC retained the amounts drawn under the
LOC, the EPC retainage amounts and the EPC contract balance and will pay to
Kvaerner three equal installments of $2.25 million payable in January of 2003,
2004 and 2005.

J. PIPELINE LITIGATION

In 1998, the United States Department of Justice informed the then current
owners of Kern River and Northern Natural Gas that Jack Grynberg, an individual,
had filed claims in the United States District Court for the District of
Colorado under the False Claims Act against such entities and certain of their
subsidiaries including Kern River and Northern Natural Gas. Mr. Grynberg has
also filed claims against numerous other energy companies and alleges that the
defendants violated the False Claims Act in connection with the measurement and
purchase of hydrocarbons. The relief sought is an unspecified amount of
royalties allegedly not paid to the federal government, treble damages, civil
penalties, attorneys' fees and costs. On April 9, 1999, the United States
Department of Justice announced that it declined to intervene in any of the
Grynberg qui tam cases, including the actions filed against Kern River and
Northern Natural Gas in the United States District Court for the District of
Colorado. On October 21, 1999, the Panel on Multi-District Litigation
transferred the Grynberg qui tam cases, including the ones filed against Kern
River and Northern Natural Gas, to the United States District Court for the
District of Wyoming for pre-trial purposes. Motions to dismiss the complaint,
filed by various defendants including Northern Natural Gas and Williams, which
was the former owner of Kern River, were denied on May 18, 2001. In connection
with the purchase of Kern River from Williams in March 2002, Williams agreed to
indemnify us against any liability for this claim; however, no assurance can be
given as to the ability of Williams to perform on this indemnity should it
become necessary. No such indemnification was obtained in connection with the
purchase of Northern Natural Gas in August 2002. We believe that the Grynberg
cases filed against Kern River and Northern Natural Gas are without merit and
Williams, on behalf of Kern River pursuant to its agreement to indemnify us, and
Northern Natural Gas, intends to defend these actions vigorously.

F-15

Judicial District, District Court, Stevens County Kansas, Civil Department
against other defendants, generally pipeline and gathering companies, since May
20, 1999. The plaintiffs allege that the defendants have engaged in
mismeasurement techniques that distort the heating content of natural gas,
resulting in an alleged underpayment of royalties to the class of producer
plaintiffs. In November 2001, Kern River and Northern Natural Gas, along with
the coordinating defendants, filed a motion to dismiss under Rules 9B and 12B of
the Kansas Rules of Civil Procedure. In January 2002, Kern River and Northern
Natural Gas and most of the coordinating defendants filed a motion to dismiss
for lack of personal jurisdiction. The court has yet to rule on these motions.
The plaintiffs filed for certification of the plaintiff class on September 16,
2002. Williams has agreed to indemnify us against any liability associated with
Kern River for this claim; however, no assurance can be given as to the ability
of Williams to perform on this indemnity should it become necessary. Williams,
on behalf of Kern River and other entities, anticipates joining with Northern
Natural Gas and other defendants in contesting certification of the plaintiff
class. Kern River and Northern Natural Gas believe that this claim is without
merit and that Kern River's and Northern Natural Gas' gas measurement techniques
have been in accordance with industry standards and its tariff.

K. PIPELINE EXPANSION GUARANTEE

On July 17, 2002, Kern River received approval from the FERC to construct, own
and operate the 2003 Expansion Project. The 2003 Expansion Project will loop
most of Kern River's existing mainline, construct three new compressor stations
and upgrade or modify Kern River's six existing compressor stations. The 2003
Expansion Project, which is expected to be completed and operational by May
2003, will increase Kern River's capacity by approximately 900mmcf/day. Service
will be provided under long-term contracts subject to incremental rates. The
estimated cost of the expansion is approximately $1.2 billion, which will be
financed with 70% debt and 30% equity, consistent with Kern River's existing
capital structure, the application for the FERC approval described above and the
limitations contained in the indenture for Kern River's existing secured senior
notes.

Construction will initially be funded with the proceeds of an $875 million
credit facility entered into by Kern River on June 21, 2002, until 70% of the
projected capitalized costs of the 2003 Expansion Project has been spent. The
final 30% of the capitalized costs of the 2003 Expansion Project will be funded
with equity from the Company. The credit facility is structured as a two-year
construction facility followed by a term loan with a final maturity 15 years
after completion of the 2003 Expansion Project. However, Kern River presently
intends to refinance the credit facility through a bond offering or other
capital markets transaction following completion of the 2003 Expansion Project.
Prior to completion of the 2003 Expansion Project, the credit facility lenders
will have limited recourse to Kern River and its assets and cash flow, and will
have recourse to the Company's completion guarantee described below. Following
completion of the 2003 Expansion Project, until such time as the Kern River
credit facility is refinanced, the lenders under the credit facility will share
equally and ratably with the existing Kern River senior secured noteholders in
all of the collateral pledged to such senior secured noteholders.

F-16

to incur the obligation to pay reservation fees thereunder; and that the FERC
shall have authorized Kern River to begin collecting rates under its tariff and
its shipper agreements; provided that the 2003 Expansion Project shall still be
deemed to have been completed if it is less than substantially complete but it
demonstrates at least 80% design capacity and Kern River's debt service coverage
ratios as defined in its senior secured note indenture are not less than 1:55 to
1:0. There are a number of other conditions to completion, including
requirements that all conditions to completion of the expansion contained in
Kern River's senior secured note indenture be satisfied and all of Kern River's
obligations under its credit agreement then share pari passu in all collateral
available to Kern River's senior secured noteholders. The Company's completion
guarantee shall terminate upon the earlier of completion of the 2003 Expansion
Project or repayment in full of all obligations under the Kern River credit
facility.

L. MANUFACTURED GAS PLANT

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

MidAmerican Energy has evaluated or is evaluating 27 properties that were, at
one time, sites of gas manufacturing plants in which it may be a potentially
responsible party. The purpose of these evaluations is to determine whether
waste materials are present, whether the materials constitute an environmental
or health risk, and whether MidAmerican Energy has any responsibility for
remedial action. Investigations of the sites are at various stages, and
MidAmerican Energy has conducted ten removal actions to date. MidAmerican Energy
is continuing to evaluate several of the sites to determine the appropriate site
remedies, if any, necessary to obtain site closure from the agencies.

MidAmerican Energy estimates the range of possible costs for investigation,
remediation and monitoring for the sites discussed above to be $16 million to
$30 million. MidAmerican Energy's estimate of the probable cost for these sites
as of September 30, 2002, was $18 million. The estimate consists of $1 million
for investigation costs, $6 million for remediation costs, $9 million for ground
water treatment and monitoring costs and $2 million for closure and
administrative costs. This estimate has been recorded as a liability and a
regulatory asset for future recovery. MidAmerican Energy projects that these
amounts will be paid or incurred over the next 5 years.

The estimate of probable remediation costs is established on a site-specific
basis. Initially, a determination is made as to whether MidAmerican Energy has
potential remedial liability for the site and whether information exists to
indicate that contaminated wastes remain at the site. When a potential remedial
liability exists, the best estimate of projected site closure costs are accrued.
The estimates are evaluated and revised quarterly as appropriate based on
additional information obtained during investigation and remedial activities.
The estimated recorded liabilities for these properties include incremental
direct costs of the remediation effort and oversight by the appropriate
regulatory authority, costs for future monitoring at sites and costs of
compensation to employees for time expected to be spent directly on the
remediation effort. The estimated recorded liability could change materially
based on facts and circumstances derived from site investigations, changes in
required remedial action and changes in technology relating to remedial
alternatives. Insurance recoveries have been received for some of the sites
under investigation. Those recoveries are intended to be used principally for
accelerated remediation, as specified by the Iowa Utilities Board, and are
recorded as a regulatory liability. Additionally, as viable potentially
responsible parties are identified, those parties are evaluated for potential
contributions, and cost recovery is pursued when appropriate.

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

13. SUBSEQUENT EVENTS

On October 4, 2002, the Company issued $200 million of 4.625% Senior Notes due
in 2007 and $500 million of 5.875% Senior Notes due in 2012. The proceeds are
being used for general corporate

F-17

purposes including to reduce short-term obligations, to make a $150 million
equity contribution to Northern Natural Gas, and to make funds available to Kern
River for its 2003 Expansion Project.

On October 15, 2002, Northern Natural Gas issued $300 million of 5.375% Senior
Notes due in 2012. The proceeds, along with the $150 million equity contribution
from the Company, were used to refinance a $450 million short-term debt
obligation.

14. SEGMENT INFORMATION

The Company has identified seven reportable operating segments principally based
on management structure: MidAmerican Energy (domestic utility operations), CE
Electric UK Funding (foreign utility operations), Kern River and Northern
Natural Gas (domestic natural gas pipeline operations), CalEnergy
Generation-Domestic, CalEnergy Generation-Foreign (primarily the Philippines),
and HomeServices (real estate operations). Information related to the Company's
reportable operating segments is shown below (in thousands).

THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
------------------------------ ------------------------------
2002 2001 2002 2001
-------------- ------------- -------------- -------------

OPERATING REVENUE:
MidAmerican Energy ....................... $ 538,696 $ 507,661 $1,582,609 $1,897,792
CE Electric UK Funding ................... 193,360 316,252 596,958 1,222,324
Kern River ............................... 39,867 -- 87,048 --
Northern Natural Gas ..................... 39,098 -- 39,098 --
CalEnergy Generation -- Domestic ......... 13,717 25,592 27,627 32,635
CalEnergy Generation -- Foreign .......... 84,227 48,782 234,686 147,589
HomeServices ............................. 340,692 193,123 855,919 473,457
---------- ---------- ---------- ----------
Segment operating revenue ................ 1,249,657 1,091,410 3,423,945 3,773,797
Corporate ................................ (11,194) (14,624) (19,412) (16,866)
---------- ---------- ---------- ----------
$1,238,463 $1,076,786 $3,404,533 $3,756,931
========== ========== ========== ==========

INCOME (LOSS) ON EQUITY INVESTMENTS:
MidAmerican Energy ....................... $ (4,582) $ 878 $ 1,394 $ 1,595
CalEnergy Generation -- Domestic ......... 12,424 5,454 21,194 22,027
HomeServices ............................. 3,071 -- 6,984 --
---------- ---------- ---------- ----------
Segment income on equity investments...... 10,913 6,332 29,572 23,622
Corporate ................................ 26 -- 291 --
---------- ---------- ---------- ----------
$ 10,939 $ 6,332 $ 29,863 $ 23,622
========== ========== ========== ==========

DEPRECIATION AND AMORTIZATION:
MidAmerican Energy ....................... $ 66,946 $ 63,017 $ 208,726 $ 217,260
CE Electric UK Funding ................... 28,390 31,219 87,200 97,141
Kern River ............................... 4,900 -- 12,161 --
Northern Natural Gas ..................... 5,755 -- 5,755 --
CalEnergy Generation -- Domestic ......... 2,160 2,058 6,517 3,375
CalEnergy Generation -- Foreign .......... 22,009 16,537 66,273 49,715
HomeServices ............................. 5,722 4,207 18,035 12,618
---------- ---------- ---------- ----------
Segment depreciation and amortization..... 135,882 117,038 404,667 380,109
Corporate ................................ (6,520) 5,648 (18,136) 15,144
---------- ---------- ---------- ----------
$ 129,362 $ 122,686 $ 386,531 $ 395,253
========== ========== ========== ==========

INTEREST EXPENSE, NET:
MidAmerican Energy ....................... $ 30,220 $ 28,359 $ 89,489 $ 86,789
CE Electric UK Funding ................... 47,819 22,933 136,250 67,308

F-18

THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
------------------------- ----------------------------
2002 2001 2002 2001
------------ ---------- ------------- ------------

Kern River ................................. 12,877 -- 22,406 --
Northern Natural Gas ....................... 7,992 -- 7,992 --
CalEnergy Generation -- Domestic ........... 5,005 5,063 15,040 5,900
CalEnergy Generation -- Foreign ............ 16,923 6,584 51,853 22,160
HomeServices ............................... 1,121 822 3,334 2,930
------ ----- ------ ------
Segment interest expense, net .............. 121,957 63,761 326,364 185,087
Corporate .................................. 37,341 36,171 112,506 105,066
------- ------ ------- -------
$ 159,298 $ 99,932 $ 438,870 $ 290,153
========= ======== ========== =========

INCOME (LOSS) BEFORE PROVISION FOR
INCOME TAXES:
MidAmerican Energy ......................... $ 108,577 $ 80,453 $ 218,565 $ 204,348
CE Electric UK Funding ..................... 39,968 98,961 197,223 186,248
Kern River ................................. 16,774 -- 39,387 --
Northern Natural Gas ....................... (1,015) -- (1,015) --
CalEnergy Generation -- Domestic ........... 14,649 22,994 12,983 37,383
CalEnergy Generation -- Foreign ............ 40,208 20,757 103,994 66,330
HomeServices ............................... 26,475 19,077 52,506 31,689
--------- -------- ---------- ---------
Segment income before provision for
income taxes .............................. 245,636 242,242 623,643 525,998
Corporate .................................. (38,627) 75,368 (131,451) (23,269)
--------- -------- ---------- ---------
$ 207,009 $317,610 $ 492,192 $ 502,729
========= ======== ========== =========

PROVISION (BENEFIT) FOR INCOME TAXES:
MidAmerican Energy ......................... $ 44,702 $ 36,079 $ 89,705 $ 92,349
CE Electric UK Funding ..................... (9,627) 177,700 5,949 205,407
Kern River ................................. 6,297 -- 15,001 --
Northern Natural Gas ....................... (399) -- (399) --
CalEnergy Generation -- Domestic ........... 844 7,013 (3,318) 5,137
CalEnergy Generation -- Foreign ............ 5,575 4,793 18,256 11,982
HomeServices ............................... 11,131 7,439 21,161 12,051
--------- -------- ---------- ---------
Segment provision for income taxes ......... 58,523 233,024 146,355 326,926
Corporate .................................. (31,735) 8,849 (66,129) (30,838)
--------- -------- ---------- ---------
$ 26,788 $241,873 $ 80,226 $ 296,088
========= ======== ========== =========

SEPTEMBER 30, DECEMBER 31,
2002 2001
--------------- -------------

IDENTIFIABLE ASSETS:
MidAmerican Energy ....................... $ 5,986,212 $ 5,848,035
CE Electric UK Funding ................... 4,526,923 4,340,147
Kern River ............................... 1,342,424 --
Northern Natural Gas ..................... 2,041,842 --
CalEnergy Generation -- Domestic ......... 928,731 870,664
CalEnergy Generation -- Foreign .......... 983,702 950,035
HomeServices ............................. 515,328 322,552
----------- -----------
Segment identifiable assets .............. 16,325,162 12,331,433
Corporate ................................ 658,888 295,219
----------- -----------
$16,984,050 $12,626,652
=========== ===========

F-19

The remaining differences from the segment amounts to the consolidated amounts
described as "Corporate" relate principally to the corporate functions including
administrative costs, corporate cash and related interest income, goodwill
amortization in 2001, intersegment eliminations, and fair value and goodwill
adjustments relating to acquisitions and disposals.

EXCESS OF COST OVER FAIR VALUE OF NET ASSETS ACQUIRED, NET:

NORTHERN CALENERGY
MIDAMERICAN CE ELECTRIC NATURAL GENERATION
ENERGY UK FUNDING KERN RIVER GAS -- DOMESTIC HOMESERVICES TOTAL
------------- ------------- ------------ ---------- ------------- -------------- -------------

Goodwill at
December 31, 2001 ........ $2,148,859 $1,100,489 $ -- $ -- $ 158,708 $ 230,490 $3,638,546
Acquisitions/purchase
price accounting
adjustments .............. -- 56,626 32,704 379,464 -- 106,054 574,848
Impairment losses ......... -- -- -- -- -- -- --
Goodwill written off
related to sale of
business unit ............ -- (49,587) -- -- -- -- (49,587)
Translation adjustment..... -- 62,262 -- -- 62,262
Other adjustments ......... (1,776) (601) -- -- (324) (170) (2,871)
---------- ---------- -------- -------- --------- --------- ----------
Goodwill at
September 30, 2002 ....... $2,147,083 $1,169,189 $ 32,704 $379,464 $ 158,384 $ 336,374 $4,223,198
========== ========== ======== ======== ========= ========= ==========

F-20

INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
MidAmerican Energy Holdings Company
Des Moines, Iowa

We have audited the accompanying consolidated balance sheets of MidAmerican
Energy Holdings Company (successor to MidAmerican Energy Holdings Company
(Predecessor), referred to as "MEHC (Predecessor)") and subsidiaries (the
"Company") as of December 31, 2001 and 2000 for the Company, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the year ended December 31, 2001 for the Company, for the period January 1, 2000
to March 13, 2000 for MEHC (Predecessor), for the period March 14, 2000 to
December 31, 2000 for the Company, and for the year ended December 31, 1999 for
MEHC (Predecessor). Our audits also included the financial statement schedules
listed in Item 21. These financial statements and financial statement schedules
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and financial statement
schedules based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of MidAmerican Energy Holdings
Company and subsidiaries as of December 31, 2001 and 2000, and the results of
their operations and their cash flows for the above stated periods in
conformity with accounting principles generally accepted in the United States
of America. Also, in our opinion, such financial statement schedules, when
considered in relation to the basic consolidated financial statements taken as
a whole, present fairly in all material respects the information set forth
therein.

As discussed in Note 2 to the consolidated financial statements, in 2001 the
Company changed its accounting policy for major maintenance, overhaul and well
workover costs.

DELOITTE & TOUCHE LLP
Des Moines, Iowa
January 17, 2002

(March 27, 2002 as to Notes 20.A. and 21 and August 2, 2002 as to Note 23)

F-21

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

AS OF DECEMBER 31,
-------------------------------
2001 2000
-------------- --------------

ASSETS
Current Assets:
Cash and investments .................................................. $ 386,745 $ 38,152
Restricted cash and short term investments ............................ 30,565 42,129
Accounts receivable ................................................... 332,553 833,757
Inventories ........................................................... 103,078 81,943
Other current assets .................................................. 131,968 96,784
----------- -----------
Total Current Assets ................................................ 984,909 1,092,765
Property, plant, contracts and equipment, net .......................... 6,527,448 5,348,647
Excess of cost over fair value of net assets acquired, net ............. 3,639,088 3,673,150
Regulatory assets ...................................................... 221,120 240,934
Long-term restricted cash and investments .............................. 24,207 48,747
Nuclear decommissioning trust fund and other marketable securities ..... 160,938 202,227
Equity investments ..................................................... 259,619 246,466
Deferred charges, other investments and other assets ................... 798,004 758,003
----------- -----------
Total Assets ........................................................ $12,615,333 $11,610,939
=========== ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable ...................................................... $ 266,027 $ 586,644
Accrued interest ...................................................... 130,569 107,726
Accrued taxes ......................................................... 88,973 125,645
Other accrued liabilities ............................................. 308,924 250,975
Short-term debt ....................................................... 256,012 261,656
Current portion of long-term debt ..................................... 317,180 438,978
----------- -----------
Total Current Liabilities ........................................... 1,367,685 1,771,624
Other long-term accrued liabilities .................................... 526,176 976,030
Parent company debt .................................................... 1,834,498 1,829,971
Subsidiary and project debt ............................................ 4,754,811 3,388,696
Deferred income taxes .................................................. 1,284,268 945,028
----------- -----------
Total Liabilities ................................................... 9,767,438 8,911,349
----------- -----------
Deferred income ........................................................ 85,917 79,489
Minority interest ...................................................... 44,477 11,491
Company-obligated mandatorily redeemable preferred securities of
subsidiary trusts ..................................................... 788,151 786,523
Subsidiary-obligated mandatorily redeemable preferred securities of
subsidiary trusts ..................................................... 100,000 100,000
Preferred securities of subsidiaries ................................... 121,183 145,686

Commitments and contingencies (Note 20)

Stockholders' Equity:
Zero coupon convertible preferred stock -- authorized 50,000 shares,
no par value, 34,563 shares outstanding at December 31, 2001 and
2000 .................................................................. -- --
Common stock -- authorized 60,000 no par value; 9,281 shares issued
and outstanding at December 31, 2001 and 2000 ......................... -- --
Additional paid in capital ............................................. 1,553,073 1,553,073
Retained earnings ...................................................... 223,926 81,257
Accumulated other comprehensive loss, net .............................. (68,832) (57,929)
----------- -----------
Total Stockholders' Equity ............................................ 1,708,167 1,576,401
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ............................. $12,615,333 $11,610,939
=========== ===========

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

F-22

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)

MEHC (PREDECESSOR)
-------------------------------
YEAR ENDED MARCH 14, 2000 JANUARY 1, 2000 YEAR ENDED
DECEMBER 31, THROUGH THROUGH DECEMBER 31,
2001 DECEMBER 31, 2000 MARCH 13, 2000 1999
-------------- ------------------- ----------------- -------------

REVENUE:
Operating revenue ........................... $5,060,605 $4,147,867 $1,087,125 $4,184,546
Interest and other income ................... 96,706 94,882 19,484 143,175
Gains on non-recurring items (Notes 3
and 15) ................................... 179,493 -- -- 138,704
---------- ---------- ---------- ----------
TOTAL REVENUES ............................... 5,336,804 4,242,749 1,106,609 4,466,425
---------- ---------- ---------- ----------

COSTS AND EXPENSES:
Cost of sales ............................... 2,705,002 2,424,279 605,439 2,199,700
Operating expense ........................... 1,176,422 904,511 219,303 1,001,384
Depreciation and amortization ............... 538,702 383,351 97,278 427,690
Interest expense ............................ 499,263 396,773 101,330 496,578
Less interest capitalized ................... (86,469) (85,369) (15,516) (70,405)
Losses on non-recurring items (Notes 3
and 15) ................................... -- -- 7,605 54,409
---------- ---------- ---------- ----------
TOTAL COSTS AND EXPENSES ..................... 4,832,920 4,023,545 1,015,439 4,109,356
---------- ---------- ---------- ----------

Income before provision for income taxes ..... 503,884 219,204 91,170 357,069
Provision for income taxes ................... 250,064 53,277 31,008 93,475
---------- ---------- ---------- ----------

Income before minority interest .............. 253,820 165,927 60,162 263,594
Minority interest ............................ 106,547 84,670 8,850 46,923
---------- ---------- ---------- ----------

INCOME BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE ........................ 147,273 81,257 51,312 216,671

Extraordinary item, net of tax ............... -- -- -- (49,441)
Cumulative effect of change in accounting
principle, net of tax ....................... (4,604) -- -- --
---------- ---------- ---------- ----------

NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS ................................ $ 142,669 $ 81,257 $ 51,312 $ 167,230
========== ========== ========== ==========

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

F-23

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 2001
(IN THOUSANDS)

OUTSTANDING ADDITIONAL
COMMON COMMON PAID-IN
SHARES STOCK CAPITAL
------------- -------- --------------

BALANCE JANUARY 1, 1999 ....................... 59,605 $-- $1,238,690

Net income .................................... -- -- --
Other Comprehensive Income:
Foreign currency translation adjustment *..... -- -- --
Unrealized losses on securities, net of tax
of $14....................................... -- -- --
Comprehensive income ..........................
Issuance of stock by subsidiary ............... -- -- 9,113
Exercise of stock options and other equity
transactions ................................. 238 -- (2,628)
Purchase of treasury stock .................... (3,376) -- --
Conversion of TIDES I ......................... 3,477 -- 2,845
Tax benefit from stock plan ................... -- -- 1,059
------ --- ----------
BALANCE DECEMBER 31, 1999 ..................... 59,944 -- 1,249,079

Net income January 1, 2000
through March 13, 2000 ....................... -- -- --
Net income March 14, 2000
through December 31, 2000 .................... -- -- --
Other Comprehensive Income:
Foreign currency translation adjustment *..... -- -- --
Minimum pension liability adjustment,
net of tax of $1,699 ........................ -- -- --
Unrealized losses on securities,
net of tax of $1,164......................... -- -- --

Comprehensive income ..........................

Exercise of stock options and
other equity transactions .................... 13 -- (138)
Teton Transaction ............................. (50,676) -- 304,132
------- --- ----------
BALANCE DECEMBER 31, 2000 ..................... 9,281 -- 1,553,073

Net income .................................... -- -- --
Other Comprehensive Income:
Foreign currency translation
adjustment * ................................ -- -- --
Fair value adjustment on cash flow
hedges, net of tax of $8,143................. -- -- --
Minimum pension liability adjustment,
net of tax of $3,448 ........................ -- -- --
Unrealized losses on securities,
net of tax of $1,315......................... -- -- --
Comprehensive income ..........................
------- --- ----------
BALANCE DECEMBER 31, 2001 ..................... 9,281 $-- $1,553,073
======= === ==========

ACCUMULATED
OTHER
COMPREHENSIVE
RETAINED INCOME TREASURY
EARNINGS (LOSS) STOCK TOTAL
------------- -------------- -------------- -------------

BALANCE JANUARY 1, 1999 ....................... $ 340,496 $ 45 $ (752,178) $ 827,053
Net income .................................... 167,230 -- -- 167,230
Other Comprehensive Income:
Foreign currency translation adjustment *..... -- (12,047) -- (12,047)
Unrealized losses on securities, net of tax
of $14....................................... -- (27) -- (27)
----------
Comprehensive income .......................... 155,156
Issuance of stock by subsidiary ............... -- -- -- 9,113
Exercise of stock options and other equity
transactions ................................. -- -- 7,779 5,151
Purchase of treasury stock .................... -- -- (104,847) (104,847)
Conversion of TIDES I ......................... -- -- 99,058 101,903
Tax benefit from stock plan ................... -- -- -- 1,059
---------- --------- ---------- ----------
BALANCE DECEMBER 31, 1999 ..................... 507,726 (12,029) (750,188) 994,588

Net income January 1, 2000
through March 13, 2000 ....................... 51,312 -- -- 51,312
Net income March 14, 2000
through December 31, 2000 .................... 81,257 -- -- 81,257
Other Comprehensive Income:
Foreign currency translation adjustment *..... -- (82,996) -- (82,996)
Minimum pension liability adjustment,
net of tax of $1,699 ........................ -- (2,388) -- (2,388)
Unrealized losses on securities,
net of tax of $1,164......................... -- 2,160 -- 2,160
----------
Comprehensive income .......................... 49,345

Exercise of stock options and
other equity transactions .................... -- -- 418 280
Teton Transaction ............................. (559,038) 37,324 749,770 532,188
---------- --------- ---------- ----------
BALANCE DECEMBER 31, 2000 ..................... 81,257 (57,929) -- 1,576,401

Net income .................................... 142,669 -- -- 142,669
Other Comprehensive Income:
Foreign currency translation
adjustment * ................................ -- (22,103) -- (22,103)
Fair value adjustment on cash flow
hedges, net of tax of $8,143................. -- 18,490 -- 18,490
Minimum pension liability adjustment,
net of tax of $3,448 ........................ -- (4,847) -- (4,847)
Unrealized losses on securities,
net of tax of $1,315......................... -- (2,443) -- (2,443)
----------
Comprehensive income .......................... 131,766
---------- --------- ---------- ----------
BALANCE DECEMBER 31, 2001 ..................... $ 223,926 $ (68,832) $ -- $1,708,167
========== ========= ========== ==========

- ----------

* Foreign currency translation adjustment has no tax effect

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

F-24

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

YEAR ENDED
DECEMBER 31, 2001
-------------------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................... $ 142,669
Adjustments to reconcile net cash flows from
operating activities:
Gains on non-recurring items ........................... (179,493)
Extraordinary item, net of tax ......................... --
Cumulative effect of change in accounting
principle, net of tax ................................. 4,604
Depreciation and amortization .......................... 442,284
Amortization of excess of cost over fair value of
net assets acquired ................................... 96,418
Amortization of deferred financing and other
costs ................................................. 20,529
Provision for deferred income taxes .................... 152,920
Income in excess of distributions on equity
investments ........................................... (28,515)
Changes in other items:
Accounts receivable and other current assets .......... 619,827
Accounts payable, accrued liabilities, deferred
income and other .................................... (424,245)
----------
NET CASH FLOWS FROM OPERATING ACTIVITIES ................. 846,998
----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of Yorkshire Electric, MEHC (Predecessor),
and MidAmerican, net of cash acquired ................... (41,670)
Proceeds from sale of Northern Supply and qualified
facilities, net of cash disposed ........................ 377,396
Proceeds from Indonesia settlement ....................... --
Acquisition of realty companies, net of cash acquired..... (40,264)
Purchase of marketable securities ........................ --
Proceeds from sale of marketable securities .............. --
Capital expenditures relating to operating projects ...... (398,165)
Philippine construction .................................. (82,181)
Acquisition of U.K. gas assets ........................... --
Construction and other development costs ................. (96,406)
Decrease in restricted cash and investments .............. 24,540
Other .................................................... 18,206
----------
NET CASH FLOWS FROM INVESTING ACTIVITIES ................. (238,544)
----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common and preferred
stock ................................................... --
Proceeds from issuance of trust preferred securities ..... --
Repayments of parent company debt ........................ --
Net proceeds from corporate revolver ..................... 68,500
Net repayment of subsidiary short term debt .............. (74,144)
Proceeds from subsidiary and project debt ................ 200,000
Repayments of subsidiary and project debt ................ (437,372)
Deferred charges relating to debt financing .............. (2,073)
Redemption of preferred securities of subsidiaries ....... (24,910)
Purchase of treasury stock ............................... --
Other .................................................... 11,532
----------
NET CASH FLOWS FROM FINANCING ACTIVITIES ................. (258,467)
----------
Effect of exchange rate changes .......................... (1,394)
----------
Net increase (decrease) in cash and cash equivalents...... 348,593
Cash and cash equivalents at beginning of period ......... 38,152
----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ............... $ 386,745
==========

Supplemental Disclosures:
Interest paid, net of amount capitalized ................. $ 389,953
==========
Income taxes paid ........................................ $ 133,139
==========

MEHC (PREDECESSOR)
---------------------------------
MARCH 14, 2000 JANUARY 1, 2000 YEAR ENDED
THROUGH THROUGH DECEMBER 31,
DECEMBER 31, 2000 MARCH 13, 2000 1999
------------------- ----------------- ---------------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................... $ 81,257 $ 51,312 $ 167,230
Adjustments to reconcile net cash flows from
operating activities:
Gains on non-recurring items ........................... -- -- (138,704)
Extraordinary item, net of tax ......................... -- -- 49,441
Cumulative effect of change in accounting
principle, net of tax ................................. -- -- --
Depreciation and amortization .......................... 303,354 83,097 363,737
Amortization of excess of cost over fair value of
net assets acquired ................................... 79,997 14,181 63,953
Amortization of deferred financing and other
costs ................................................. 18,310 4,075 18,181
Provision for deferred income taxes .................... (15,460) 7,735 (56,590)
Income in excess of distributions on equity
investments ........................................... (26,607) (3,459) (22,796)
Changes in other items:
Accounts receivable and other current assets .......... (316,287) 440 53,016
Accounts payable, accrued liabilities, deferred
income and other .................................... 121,843 13,702 57,491
------------- ---------- -------------
NET CASH FLOWS FROM OPERATING ACTIVITIES ................. 246,407 171,083 554,959
------------- ---------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of Yorkshire Electric, MEHC (Predecessor),
and MidAmerican, net of cash acquired ................... (2,048,266) -- (2,501,425)
Proceeds from sale of Northern Supply and qualified
facilities, net of cash disposed ........................ -- -- 365,074
Proceeds from Indonesia settlement ....................... -- -- 290,000
Acquisition of realty companies, net of cash acquired..... -- -- (36,858)
Purchase of marketable securities ........................ (44,686) (8,251) (92,523)
Proceeds from sale of marketable securities .............. 69,375 12,562 498,676
Capital expenditures relating to operating projects ...... (301,948) (44,355) (360,898)
Philippine construction .................................. (58,531) (22,736) (62,059)
Acquisition of U.K. gas assets ........................... -- -- (72,280)
Construction and other development costs ................. (178,250) (56,450) (180,683)
Decrease in restricted cash and investments .............. 157,905 48,788 199,588
Other .................................................... 15,241 15,568 (7,432)
------------- ---------- -------------
NET CASH FLOWS FROM INVESTING ACTIVITIES ................. (2,389,160) (54,874) (1,960,820)
------------- ---------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common and preferred
stock ................................................... 1,428,024 -- --
Proceeds from issuance of trust preferred securities ..... 454,772 -- --
Repayments of parent company debt ........................ (4,225) -- (853,420)
Net proceeds from corporate revolver ..................... 85,000 -- --
Net repayment of subsidiary short term debt .............. (88,106) (124,761) (136)
Proceeds from subsidiary and project debt ................ 262,176 6,043 1,394,094
Repayments of subsidiary and project debt ................ (234,776) (3,135) (331,880)
Deferred charges relating to debt financing .............. (3,805) -- 7,761
Redemption of preferred securities of subsidiaries ....... (20,409) -- --
Purchase of treasury stock ............................... -- -- (104,847)
Other .................................................... 198 (6,648) 4,303
------------- ---------- -------------
NET CASH FLOWS FROM FINANCING ACTIVITIES ................. 1,878,849 (128,501) 115,875
------------- ---------- -------------
Effect of exchange rate changes .......................... (1,555) (424) 165
------------- ---------- -------------
Net increase (decrease) in cash and cash equivalents...... (265,459) (12,716) (1,289,821)
Cash and cash equivalents at beginning of period ......... 303,611 316,327 1,606,148
------------- ---------- -------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ............... $ 38,152 $ 303,611 $ 316,327
============= ========== =============

Supplemental Disclosures:
Interest paid, net of amount capitalized ................. $ 351,532 $ 35,057 $ 439,894
============= ========== =============
Income taxes paid ........................................ $ 94,405 $ -- $ 130,875
============= ========== =============

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

F-25

MIDAMERICAN ENERGY HOLDINGS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BUSINESS

MidAmerican Energy Holdings Company and its subsidiaries (the "Company" or
"MEHC"), is a United States-based privately owned global energy company with
publicly traded fixed income securities that generates, distributes and supplies
energy to utilities, government entities, retail customers and other customers
located throughout the world. Through its subsidiaries the Company is organized
and managed on five separate platforms: MidAmerican Energy, CE Electric UK
Funding, CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and
HomeServices.

On March 14, 2000, the Company and an investor group comprised of Berkshire
Hathaway Inc., Walter Scott, Jr., a director of the Company, David L. Sokol,
Chairman and Chief Executive Officer of the Company, and Gregory E. Abel, Chief
Operating Officer of the Company closed on a definitive agreement and plan of
merger whereby the investor group acquired all of the outstanding common stock
of the Company (the "Teton Transaction"). As a result of the Teton Transaction,
Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel own approximately 9.7%,
86%, 3% and 1% of the voting stock respectively.

MIDAMERICAN ENERGY

MidAmerican Energy Company ("MidAmerican Energy") is a regulated public utility
principally engaged in the business of generating, transmitting, distributing
and selling electric energy and in distributing, selling and transporting
natural gas. MidAmerican Energy distributes electricity at the retail level in
Iowa, Illinois and South Dakota. It also distributes natural gas at the retail
level in Iowa, Illinois, South Dakota and Nebraska. As of December 31, 2001,
MidAmerican Energy had approximately 673,000 retail electric customers and
652,000 retail natural gas customers.

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

A substantial portion of MidAmerican Energy's business still operates in a
rate-regulated environment and, accordingly, many decisions for obtaining and
using resources are evaluated from an electric and gas regulated business
perspective. MidAmerican Energy's operations are seasonal in nature with a
disproportionate percentage of revenues and earnings historically being earned
in the Company's first and third quarters.

CE ELECTRIC UK FUNDING

The business of CE Electric UK Funding, an indirect wholly owned subsidiary of
the Company, consists of Northern Electric plc ("Northern"), an indirect wholly
owned subsidiary of the Company, and Yorkshire Power Group Ltd. ("Yorkshire"),
an indirect majority owned subsidiary of the Company, and CalEnergy Gas
(Holdings) Limited ("CE Gas"), an indirect wholly owned subsidiary of the
Company.

Northern's and Yorkshire's operations consist primarily of the distribution of
electricity and other auxiliary businesses in the United Kingdom. Through
September 21, 2001, Northern's operations also included the supply of
electricity and natural gas and the related metering business.

Northern and Yorkshire receive electricity from the national grid transmission
system and distribute it to customers' premises using their network of
transformers, switchgear and cables. Substantially all of the customers in their
distribution service areas are connected to their network and can only be
delivered through their distribution system, thus providing Northern and
Yorkshire with distribution volume that is stable from year to year. Northern
and Yorkshire charge access fees for the use of the distribution system. The
prices for distribution are controlled by a prescribed formula that limits
increases (and may require decreases) based upon the rate of inflation in the
United Kingdom and other regulatory action.

F-26

Northern's supply business was primarily involved in the bulk purchase of
electricity, previously through a central pool and from March 27, 2001 on
through the New Electricity Trading Agreements ("NETA"), and subsequent resale
to individual customers throughout the U.K. The supply business generally is a
high volume business that tends to operate at lower profitability levels than
the distribution business. Northern also competed to supply gas inside and
outside its authorized area. See Note 3.

CE Gas is a gas exploration and production company that is focused on developing
integrated upstream gas projects. Its "upstream gas" business consists of the
exploration, development and production, including transportation and storage,
of gas for delivery to a point of sale into either a gas supply market or a
power generation facility. CE Gas holds various interests in the southern basin
of the United Kingdom sector of the North Sea. Also, CE Gas has been involved in
certain gas development and exploration activities relating to a large gas field
prospect in Poland, the EP389 concession in the Perth Basin in Australia and the
Yolla discovery in the Bass Basin of Australia.

CALENERGY GENERATION-DOMESTIC

The Company has a 50% ownership interest in CE Generation LLC ("CE Generation")
that has interests in ten geothermal plants in the Imperial Valley, California
and three natural gas-fired cogeneration plants. For purposes of consistent
presentation, plant capacity factors for Vulcan, Hoch (Del Ranch), Turbo, Elmore
and Leathers (collectively the "Partnership Projects") are based on capacity
amounts of 34, 38, 10, 38, and 38 net MW, respectively, and for Salton Sea I,
Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V plants
(collectively the "Salton Sea Projects") are based on capacity amounts of 10,
20, 50, 40 and 49 net MW, respectively (the Partnership Projects and the Salton
Sea Projects are collectively referred to as the "Imperial Valley Projects").
Plant capacity factors for Saranac, Power Resources and Yuma (collectively the
"Gas Plants") are based on capacity amounts of 240, 200, and 50 net MW,
respectively. Each plant possesses an operating margin that allows for
production in excess of the amount listed above. Utilization of this operating
margin is based upon a variety of factors and can be expected to vary between
calendar quarters, under normal operating conditions. Due to its 50% ownership
interest in CE Generation, the Company accounts for CE Generation as an equity
investment.

Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company, operates a 537 MW gas-fired power plant in the Quad
Cities, Illinois area (the "Cordova Project"). The Cordova Project commenced
commercial operations on June 19, 2001. Cordova Energy has entered into a power
purchase agreement with a unit of El Paso Energy Corporation ("El Paso") in
which El Paso will purchase all of the capacity and energy from the project
until December 31, 2019. Cordova Energy has exercised an option under the El
Paso Power Purchase Agreement to callback 50% of the project output for sales to
others for the contract years ending on or prior to May 14, 2004. Cordova Energy
subsequently entered into a power purchase agreement with MidAmerican Energy
whereby MidAmerican Energy will purchase 50% of the capacity and energy from the
Cordova Project until May 14, 2004.

CALENERGY GENERATION-FOREIGN

The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong Projects
(collectively, the "Leyte Projects"), which are geothermal power plants located
on the island of Leyte in the Philippines, and the Casecnan Project, a combined
irrigation and hydroelectric power generation project located in the central
part of the island of Luzon in the Philippines. The Casecnan Project commenced
commercial operations on December 11, 2001. For purposes of consistent
presentation, capacity amounts for Upper Mahiao, Malitbog, Mahanagdong and
Casecnan are 119, 216, 165 and 150 net MW, respectively. Each plant possesses an
operating margin that allows for production in excess of the amount listed
above. Utilization of this operating margin is based upon a variety of factors
and can be expected to vary between calendar quarters, under normal operating
conditions.

HOMESERVICES

HomeServices.Com, Inc. ("HomeServices"), a wholly-owned subsidiary of the
Company, is the second largest residential real estate brokerage firm in the
United States based on aggregate closed transaction

F-27

sides in 2000 for its various brokerage firm operating subsidiaries. Closed
transaction sides mean either the buy side or sell side of any closed home
purchase and is the standard term used by industry participants and publications
to rank real estate brokerage firms. In addition to providing traditional
residential real estate brokerage services, HomeServices cross sells to its
existing real estate customers preclosing services, such as mortgage origination
and title services, including title insurance, title search, escrow and other
closing administrative services, assists in securing other preclosing and
postclosing services provided by third parties, such as home warranty, home
inspection, home security, property and casualty insurance, home maintenance,
repair and remodeling and is developing various related e-commerce services.
HomeServices currently operates in the following fourteen states: Minnesota,
Iowa, California, Arizona, Kansas, Missouri, Kentucky, Nebraska, Wisconsin,
Indiana, Maryland, North Dakota, South Dakota and Georgia. HomeServices
generally occupies the number one or number two market share position in each of
its major markets based on aggregate closed transaction sides for the year ended
December 31, 2001. HomeServices' major markets consist of the following
metropolitan areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa; Los
Angeles and San Diego, California; Omaha, Nebraska; Kansas City, Kansas;
Louisville, Kentucky; Springfield, Missouri; Tucson, Arizona; Annapolis,
Maryland and Atlanta, Georgia.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements include the accounts of the Company and
its wholly-owned subsidiaries. Subsidiaries which are less than 100% owned but
greater than 50% owned are consolidated with a minority interest. Subsidiaries
that are 50% owned or less, but where the Company has the ability to exercise
significant influence, are accounted for under the equity method of accounting.
Investments where the Company's ability to influence is limited are accounted
for under the cost method of accounting. All significant inter-enterprise
transactions and accounts have been eliminated. The results of operations of the
Company include the Company's proportionate share of results of operations of
entities acquired from the date of each acquisition for purchase business
combinations.

CASH EQUIVALENTS, INVESTMENTS, AND RESTRICTED CASH AND INVESTMENTS

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

The current restricted cash and short-term investments balance includes
commercial paper and money market securities, and is mainly composed of amounts
deposited in restricted accounts from which the Company will source its debt
service reserve requirements relating to the projects. These funds are
restricted by their respective project debt agreements to be used only for the
related project.

The long-term restricted cash and investments balances are mainly composed of
amounts deposited in restricted accounts from which the Company will fund the
various projects under construction.

The Company's restricted investments are classified as held-to-maturity and are
accounted for at their amortized cost basis. The carrying amount of the
investments approximates the fair value based on quoted market prices as
provided by the financial institution that holds the investments.

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

INVENTORY

Inventory is primarily composed of materials and supplies, coal stocks, gas in
storage and fuel oil. Materials and supplies, coal stocks and fuel oil are at
average cost and gas in storage is accounted for under the LIFO method.

PROPERTY, PLANT, CONTRACTS, EQUIPMENT AND DEPRECIATION

The cost of major additions and betterments are capitalized, while replacements,
maintenance, and repairs that do not improve or extend the lives of the
respective assets are expensed.

F-28

Depreciation of the operating power plant costs, net of salvage value, is
computed on the straight-line method over the estimated useful lives, between
ten and thirty years. Depreciation of furniture, fixtures and equipment that are
recorded at cost, is computed on the straight-line method over the estimated
useful lives of the related assets, which range from three to ten years.

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

Expenditures on major information technology systems are capitalized and
depreciated on a straight-line basis over the estimated useful lives of the
developed systems that range from three to fifteen years.

An allowance for the estimated annual decommissioning costs of the Quad Cities
Generating Station ("Quad Cities Station") equal to the level of funding is
included in depreciation expense. See Note 20 for additional information
regarding decommissioning costs.

EXCESS OF COST OVER FAIR VALUE OF NET ASSETS ACQUIRED

Total acquisition costs in excess of the fair values assigned to the net assets
acquired are amortized using the straight line method over a 25 to 40 year
period.

IMPAIRMENT OF LONG-LIVED ASSETS

The Company reviews long-lived assets and certain identifiable intangibles for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. An impairment loss would be
recognized, based on discounted cash flows or various fair value models,
whenever evidence exists that the carrying value is not recoverable.

CONTINGENT LIABILITIES

The Company is subject to the possibility of various loss contingencies arising
in the ordinary course of business. Management considers the likelihood of the
loss or impairment of an asset or the incurrence of a liability as well as our
ability to reasonably estimate the amount of loss in determining loss
contingencies. An estimated loss contingency is accrued when it is probable that
a liability has been incurred or an asset has been impaired and the amount of
loss can be reasonably estimated. The Company regularly evaluates current
information available to determine whether such accruals should be adjusted.

REVENUE RECOGNITION

Revenues are recorded based upon services rendered and electricity, gas and
steam delivered, distributed or supplied to the end of the period. Where there
is an over recovery of distribution business revenues against the maximum
regulated amount, revenues are deferred equivalent to the over recovered amount.
The deferred amount is deducted from revenue and included in other liabilities.
Where there is an under recovery, no anticipation of any potential future
recovery is made.

The Company also records unbilled revenues representing the estimated amounts
customers will be billed for services rendered between the meter reading dates
in a particular month and the end of that month. Accrued unbilled revenues are
included in accounts receivable on the consolidated balance sheets.

CAPITALIZATION OF INTEREST AND DEFERRED FINANCING COSTS

Prior to the commencement of operations, interest is capitalized on the costs of
the construction projects and resource development to the extent incurred.
Capitalized interest and other deferred charges are amortized over the lives of
the related assets.

Deferred financing costs are amortized over the term of the related financing
using the effective interest method.

F-29

DEFERRED INCOME TAXES

The Company recognizes deferred tax assets and liabilities based on the
difference between the financial statement and tax basis of assets and
liabilities using estimated tax rates in effect for the year in which the
differences are expected to reverse. The Company does not intend to repatriate
earnings of foreign subsidiaries in the foreseeable future. As a result,
deferred United States income taxes are not provided for retained earnings of
international subsidiaries and corporate joint ventures unless the earnings are
intended to be remitted.

FINANCIAL INSTRUMENTS

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

FOREIGN CURRENCY TRANSLATION AND TRANSACTIONS

For the Company's foreign operations whose functional currency is not the U.S.
dollar, the assets and liabilities are translated into U.S. dollars at current
exchange rates. Resulting translation adjustments are reflected as accumulated
other comprehensive income (loss) in stockholders' equity. Revenues and expenses
are translated at average exchange rates for the year.

Transaction gains and losses that arise from exchange rate fluctuations on
transactions denominated in a currency other than the functional currency,
except those transactions which operate as a hedge of an identifiable foreign
currency commitment or as a hedge of a foreign currency investment position, are
included in the results of operations as incurred.

RECLASSIFICATION

Certain amounts in the fiscal 2000 and 1999 consolidated financial statements
and supporting note disclosures have been reclassified to conform to the fiscal
2001 presentation. Such reclassification did not impact previously reported net
income or retained earnings.

USE OF ESTIMATES

The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.

ACCOUNTING FOR LONG-TERM POWER PURCHASE CONTRACT

Under a long-term power purchase contract with Nebraska Public Power District
("NPPD"), expiring in 2004, MidAmerican Energy purchases one-half of the output
of the 778-megawatt Cooper Nuclear Station ("Cooper"). The consolidated balance
sheets include a liability for MidAmerican Energy's fixed obligation to pay 50%
of NPPD's Nuclear Facility Revenue Bonds and other fixed liabilities. A like
amount representing MidAmerican Energy's right to purchase power is shown as an
asset.

Cooper capital improvement costs prior to 1997, including carrying costs, were
deferred in accordance with then applicable rate regulation and are being
amortized and recovered in rates over either a five-year period or the remaining
term of the power purchase contract. Beginning July 11, 1997, the Iowa portion
of capital improvement costs is recovered currently from customers and is
expensed as incurred. For jurisdictions other than Iowa, MidAmerican Energy
began charging Cooper capital improvement costs to expense as incurred in
January 1997.

F-30

The fuel cost portion of the power purchase contract is included in cost of
sales. All other costs MidAmerican Energy incurs in relation to its long-term
power purchase contract with NPPD are included in operating expense.

ACCOUNTING PRINCIPLE CHANGE

Effective January 1, 2001, the Company has changed its accounting policy
regarding major maintenance and repairs for nonregulated gas projects,
nonregulated plant overhaul costs and geothermal well rework costs to the direct
expense method from the former policy of monthly accruals based on long-term
scheduled maintenance plans for the gas projects and deferral and amortization
of plant overhaul costs and geothermal well rework costs over the estimated
useful lives. The cumulative effect of the change in accounting principle was
$4.6 million, net of taxes of $.7 million. If the Company had adopted the policy
as of January 1, 2000, income before extraordinary item and cumulative effect of
change in accounting principle would have been $6.3 million lower in 2000 on a
proforma basis.

ACCOUNTING FOR DERIVATIVES

The Company is exposed to market risk, including changes in the market price of
certain commodities and interest rates. To manage the price volatility relating
to these exposures, the Company enters into various financial derivative
instruments. Senior management provides the overall direction, structure,
conduct and control of the Company's risk management activities, including the
use of financial derivative instruments, authorization and communication of risk
management policies and procedures, strategic hedging program guidelines,
appropriate market and credit risk limits, and appropriate systems for
recording, monitoring and reporting the results of transactional and risk
management activities. The Company uses hedge accounting for derivative
instruments pertaining to its natural gas purchasing, wholesale electricity
activities, financing activities and preferred stock investing operations.

On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards Nos. 133 and 138 (SFAS Nos. 133/138) pertaining to the accounting for
derivative instruments and hedging activities. SFAS Nos. 133/138 requires an
entity to recognize all of its derivatives as either assets or liabilities in
its statement of financial position and measure those instruments at fair value.
If the conditions specified in SFAS Nos. 133/138 are met, those instruments may
be designated as hedges. Changes in the value of hedge instruments would not
impact earnings, except to the extent that the instrument is not perfectly
effective as a hedge. At January 1, 2001, the Company recognized $44.9 million
and $38.0 million of energy-related assets and liabilities, respectively, as
being subject to fair value accounting pursuant to SFAS Nos. 133/138, all of
which are accounted for as hedges. Additionally, on January 1, 2001, the
Company's portfolio of preferred stock investments was transferred from the
available for sale category to the trading category, as permitted by SFAS No.
133. Initial adoption of SFAS Nos. 133/138 did not have a material impact on the
results of operations for the Company.

NEW ACCOUNTING PRONOUNCEMENTS

In July 2001, the FASB issued SFAS No. 141, "Business Combinations", and SFAS
No. 142, "Goodwill and Other Intangible Assets" which establish accounting and
reporting for business combinations. SFAS No. 141 requires all business
combinations entered into subsequent to June 30, 2001, to be accounted for using
the purchase method of accounting. SFAS No. 142 provides that goodwill and other
intangible assets with indefinite lives will not be amortized but tested for
impairment on an annual basis. SFAS No. 142 is effective for the Company
beginning January 1, 2002. Under the current method of assessing goodwill for
impairment, which uses an undiscounted cash flow approach, no material
impairment existed at December 31, 2001. For 2002, the Company will begin to
test goodwill for impairment under the new rules, applying a fair-value-based
approach. The Company is in the process of quantifying the anticipated impact on
its financial condition and results of operations of adopting the provisions of
SFAS No. 142, which could be significant. The historical impact of not
amortizing goodwill would have been to increase net income for the years ended
December 31, 2001, 2000 and 1999 by $94.4 million, $92.4 million and $62.3
million, respectively. However, impairment reviews may result in future periodic
write-downs.

F-31

In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations", which addresses the accounting for legal obligations associated
with the retirement of tangible, long-lived assets, and the associated asset
retirement costs. This pronouncement is effective for years beginning after June
15, 2002. The Company is evaluating the impact that adoption of this standard
will have on its financial statements.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets", which addresses the financial accounting and
reporting for the impairment or disposal of long-lived assets. This
pronouncement is effective for years beginning after December 15, 2001. The
Company is evaluating the impact that adoption of this standard will have on its
financial statements, but does not believe it will have a material impact on its
financial statements.

3. ACQUISITIONS/DISPOSITIONS

YORKSHIRE SWAP

On September 21, 2001, CE Electric UK Ltd., an indirect wholly owned subsidiary
of the Company, and Innogy Holdings, plc executed an agreement to exchange
Northern's electricity and gas supply and metering assets for Innogy's 94.75%
interest in Yorkshire's electricity distribution business. Northern's supply
business was initially valued at approximately $430 million ((pounds
sterling)295 million), including working capital of approximately $53 million
((pounds sterling)37 million). 94.75% of Yorkshire's distribution business was
initially valued at approximately $395 million ((pounds sterling)271 million),
including working capital of approximately $48 million ((pounds sterling)33
million). The net cash received by Northern for the exchange was approximately
$35 million ((pounds sterling)24 million). Working capital is subject to
adjustment and is currently under review.

The disposition of Northern's supply business created a pre-tax non-recurring
gain of $196.7 million and an after-tax gain of $10.8 million. Included in the
carrying value of the Northern supply business was $504.4 million of goodwill
allocated based on the relative fair values of the Northern supply business. In
connection with the sale of the Northern supply business, management intends to
sell the associated Northern retail business.

The Company paid $37.4 million, net of cash acquired of $362.8 million and
transaction costs, for 94.75% of the Yorkshire electricity distribution business
and related indebtedness. The acquisition has been accounted for as a purchase
business combination. The results of operations for Yorkshire are included in
the Company's results beginning September 21, 2001.

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

Cash .......................................................... $ 362.8
Property, plant and equipment ................................. 1,262.7
Excess of cost over fair value of net assets acquired ......... 523.6
Other assets .................................................. 11.6
----------
Total assets acquired ..................................... 2,160.7
----------
Current liabilities ........................................... (34.1)
Long-term debt ................................................ (1,503.3)
Deferred income taxes ......................................... (175.8)
Minority interest ............................................. (40.7)
Other liabilities ............................................. (6.6)
----------
Total liabilities assumed ................................. (1,760.5)
----------
Net assets acquired ........................................... $ 400.2
==========

TETON TRANSACTION

On October 24, 1999, the Company and an investor group comprised of Berkshire
Hathaway, Walter Scott, Jr., and David L. Sokol, executed a definitive
agreement and plan of merger whereby the investor

F-32

group would acquire all of the outstanding common stock of the Company for
$35.05 per share in cash, representing a total purchase price of approximately
$2.2 billion, including transaction costs (the "Teton Transaction"). The Teton
Transaction closed on March 14, 2000 and Berkshire Hathaway invested
approximately $1.24 billion in common stock and convertible preferred stock and
approximately $455 million in 11% nontransferable trust preferred securities due
March 14, 2010. Mr. Scott, Mr. Sokol and Gregory E. Abel, Chief Operating
Officer of the Company, contributed cash and current securities of the Company
having a value of approximately $310 million. The remaining purchase price was
funded with the Company's cash. Berkshire Hathaway owns approximately 9.7% of
the voting stock, Mr. Scott owns approximately 86% of the voting stock, Mr.
Sokol owns approximately 3% of the voting stock and Mr. Abel owns approximately
1% of the voting stock.

The merger has been accounted for as a purchase business combination. The
purchase price has been allocated to assets acquired and liabilities assumed.
The Company recorded goodwill of approximately $1.2 billion that is being
amortized using the straight-line method over a 40-year period.

The Company incurred approximately $7.6 million and $6.7 million of
non-recurring costs in 2000 and 1999 respectively, related to the Teton
Transaction, which were expensed.

Unaudited pro forma combined revenue, income before cumulative effect of change
in accounting principle and net income of the Company and MEHC (Predecessor) for
the years ended December 31, 2001 and 2000, as if the Yorkshire swap and the
Teton Transaction had occurred at the beginning of each year after giving effect
to pro forma adjustments related to the acquisitions, including the sale of the
Northern Supply business and the issuance of the 11% trust preferred securities,
were $4,401.0 million, $149.1 million and $144.5 million, respectively, compared
to $4,084.0 million, $113.3 million and $113.3 million, respectively.

HOMESERVICES

On October 18, 1999, the Company closed on its initial public offering of 3.25
million shares of common stock of HomeServices at $15 per share. HomeServices
sold 2.19 million newly issued shares and the Company, the selling stockholder,
sold 1.06 million of its HomeServices shares in the offering. The offering
reduced the Company's ownership in HomeServices to approximately 65%.

On April 14, 2000, the Company purchased 500,000 shares of HomeServices' common
stock for $4.2 million, increasing the Company's ownership percentage to
approximately 70%.

In October 2000, HomeServices repurchased 1.7 million shares of treasury stock
for $17.9 million. This transaction increased the Company's ownership percentage
to approximately 83%.

On August 27, 2001, the Company commenced a tender offer to purchase the
remaining outstanding shares of common stock of HomeServices for a cash purchase
price of $17 per share. On September 25, 2001, the Company announced that it had
successfully completed the tender offer for all outstanding shares of the common
stock of HomeServices for $29.3 million. As a result, the Company owns 100% of
the outstanding HomeServices common stock, although options entitling employees
to purchase HomeServices common stock remain outstanding.

F-33

4. PROPERTY, PLANT, CONTRACTS AND EQUIPMENT, NET

Property, plant, contracts and equipment, net comprise the following at December
31 (in thousands):

2001 2000
--------------- ---------------

Operating assets:
Utility generation and distribution system ............... $ 7,574,339 $ 6,132,867
Independent power plants ................................. 1,398,179 694,615
Utility non-operational assets ........................... 354,366 344,576
Power sales agreements ................................... 48,185 82,231
Realty company assets .................................... 51,150 37,936
Other assets ............................................. 47,863 53,590
------------ ------------
Total operating assets ................................... 9,474,082 7,345,815
Less accumulated depreciation and amortization ........... (3,650,862) (3,300,237)
------------ ------------
Net operating assets ..................................... 5,823,220 4,045,578
Mineral and gas reserves and exploration assets, net ..... 387,697 378,495
Construction in progress:
Zinc recovery project ................................... 163,366 165,585
Utility generation and distribution system .............. 149,225 143,261
Casecnan ................................................ -- 387,274
Cordova ................................................. -- 224,514
Other ................................................... 3,940 3,940
------------ ------------
Total .................................................... $ 6,527,448 $ 5,348,647
============ ============

ZINC RECOVERY PROJECT

The Company owns the rights to proprietary processes for the extraction of
minerals from elements in solution in the geothermal brine and fluids utilized
at its Imperial Valley plants. A pilot plant has successfully produced
commercial quality zinc at the Company's Imperial Valley Projects.

CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company, is
constructing the Zinc Recovery Project which will recover zinc from the
geothermal brine (the "Zinc Recovery Project"). Facilities are being installed
near the Imperial Valley Project's sites to extract a zinc chloride solution
from the geothermal brine through an ion exchange process. This solution will be
transported to a central processing plant where zinc ingots will be produced
through solvent extraction, electrowinning and casting processes. The Zinc
Recovery Project is designed to have a capacity of approximately 30,000 metric
tons per year and is scheduled to commence commercial operations in 2002. In
September 1999, CalEnergy Minerals LLC entered into a sales agreement whereby
all zinc produced by the Zinc Recovery Project will be sold to Cominco, Ltd. The
initial term of the agreement expires in December 2005.

The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc.
("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering,
procure, construct and manage contract (the "Zinc Recovery Project EPC
Contract"). On June 14, 2001, CalEnergy Minerals LLC issued notices of default,
termination and demand for payment of damages to Kvaerner under the Zinc
Recovery Project EPC Contract due to failure to meet performance obligations. As
a result of Kvaerner's failure to pay monetary obligations under the Zinc
Recovery Project EPC Contract, CalEnergy Minerals LLC drew $29.6 million under
the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals LLC has
entered into a time and materials reimbursable engineer, procure and
construction management contract with AMEC E&C Services, Inc. to complete the
Zinc Recovery Project.

On July 11, 2001, Kvaerner filed an Amended Demand For Arbitration against
CalEnergy Minerals LLC characterizing the nature of the dispute as concerns
regarding change orders and performance penalties. Kvaerner did not state the
amount of its claim.

On August 7, 2001, CalEnergy Minerals LLC filed an Answering Statement and
Counterclaim against Kvaerner. CalEnergy Minerals LLC denied all material
allegations in Kvaerner's Amended Demand for

F-34

Arbitration, and asserted a counterclaim against Kvaerner for breach of contract
and specific performance. CalEnergy Minerals LLC alleged that its total
estimated damage for Kvaerner's breach of contract are in excess of
approximately $60 million; however, CalEnergy Minerals LLC has offset
approximately $42.5 million of these damages by exercising its rights under the
EPC Contract to claim the retainage and by drawing on a letter of credit.
Therefore, CalEnergy Minerals LLC has asked for a judgment in excess of
approximately $20 million. The arbitration is scheduled for June 2002.

5. EQUITY INVESTMENT IN CE GENERATION

Due to the sale of 50% of its interests in CE Generation, the Company has
accounted for CE Generation as an equity investment beginning March 3, 1999. The
equity investment in CE Generation at December 31, 2001 and 2000 was
approximately $233.6 million and $220.0 million, respectively. The following is
summarized financial information for CE Generation as of and for the years ended
December 31 (in thousands):

2001 2000 1999
------------ ------------ -----------

Revenues ........................................... $ 565,838 $ 510,796 $340,683
Income before extraordinary item and cumulative
effect of change in accounting principle .......... 74,194 73,535 61,970
Net income ......................................... 58,808 73,535 44,492
Current assets ..................................... 211,635 188,234
Total assets ....................................... 1,932,119 1,984,445
Current liabilities ................................ 155,808 138,751
Long-term debt, including current portion .......... 1,096,256 1,163,729
Total liabilities .................................. 1,404,910 1,477,066

6. SHORT-TERM DEBT

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

2001 2000
----------- ----------

Corporate revolving credit facilities ........... $153,500 $ 85,000
MidAmerican Energy short-term debt .............. 91,780 81,600
HomeServices revolving credit facility .......... 9,000 10,000
Other ........................................... 1,732 85,056
-------- --------
$256,012 $261,656
======== ========

CORPORATE REVOLVING CREDIT FACILITIES

The Company has available $400 million in revolving credit facilities with $150
million expiring in June 2002 and $250 million expiring in June 2003. The
facilities are unsecured and are available to fund working capital requirements
and finance future business expansion opportunities. The facilities carry a
variable interest rate based on LIBOR and ranging from 2.8125% to 8.5% in 2001
(weighted average interest rate of 2.93% at December 31, 2001).

MIDAMERICAN ENERGY SHORT-TERM DEBT

MidAmerican Energy has authority from the Federal Energy Regulatory Commission
("FERC") to issue short-term debt in the form of commercial paper and bank notes
aggregating $500 million. As of December 31, 2001, MidAmerican Energy had in
place a $370.4 million revolving credit facility that supports its $250 million
commercial paper program and its variable rate pollution control revenue
obligations. In addition, MidAmerican Energy has a $5 million line of credit. As
of December 31, 2001, commercial paper and bank notes totaled $89.4 million for
MidAmerican Energy.

F-35

MHC Inc., an indirect wholly owned subsidiary of the Company, has a $4.0 million
line of credit under which $2.4 million was outstanding at December 31, 2001.
The commercial paper, bank notes and outstanding line of credit have a weighted
average interest rate of 1.9% at December 31, 2001.

HOMESERVICES REVOLVING CREDIT FACILITIES

HomeServices has available a $65 million senior secured revolving credit
facility of which HomeServices had drawn down approximately $9 million as of
December 31, 2001. This credit agreement has a variable interest rate at either
the prime lending rate or LIBOR plus a fixed spread of 1.25% to 2.50% that
varies based on HomeServices' cash flow leverage ratio, as defined in the
agreement. As of December 31, 2001, the blended average interest rate on the
senior secured revolving credit facility borrowings was 3.20%.

7. PARENT COMPANY DEBT

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

2001 2000
-------------- --------------

7.63% Senior Notes due 2007 ............... $ 350,000 $ 350,000
6.96% Senior Notes due 2003 ............... 215,000 215,000
7.23% Senior Notes due 2005 ............... 260,000 260,000
7.52% Senior Notes due 2008 ............... 450,000 450,000
8.48% Senior Notes due 2028 ............... 475,000 475,000
7.52% Senior Notes due 2008 ............... 101,680 101,888
Fair value adjustments and other .......... (17,182) (21,917)
---------- ----------
$1,834,498 $1,829,971
========== ==========

Interest on the 7.63% Senior Notes is payable semiannually on April 15 and
October 15 of each year. Interest on the remaining parent company debt is
payable semiannually on March 15 and September 15 of each year.

8. SUBSIDIARY AND PROJECT DEBT

Each of the Company's direct or indirect subsidiaries is organized as a legal
entity separate and apart from the Company and its other subsidiaries. Pursuant
to separate project financing agreements, the assets of each subsidiary are
pledged or encumbered to support or otherwise provide the security for their own
project or subsidiary debt. It should not be assumed that any asset of any such
subsidiary will be available to satisfy the obligations of the Company or any of
its other such subsidiaries; provided, however, that unrestricted cash or other
assets which are available for distribution may, subject to applicable law and
the terms of financing arrangements of such parties, be advanced, loaned, paid
as dividends or otherwise distributed or contributed to the Company or
affiliates thereof. "Subsidiaries" means all of the Company's direct or indirect
subsidiaries (1) owning interests in CE Electric UK Funding, MidAmerican
Funding, HomeServices, CE Generation, or the Imperial Valley, Saranac, Power
Resources, Mahanagdong, Malitbog, Upper Mahiao, Casecnan, and Cordova projects
or (2) owning interests in the subsidiaries that own interests in the foregoing
subsidiaries or projects.

F-36

Project loans held by subsidiaries and projects comprise the following at
December 31 (in thousands):

2001 2000
------------- --------------

MidAmerican Funding, LLC Senior Notes and Bonds .......... $ 700,000 $ 700,000
MidAmerican Energy Mortgage Bonds ........................ 340,570 340,570
MidAmerican Energy Pollution Control Bonds ............... 157,185 158,625
MidAmerican Energy Notes ................................. 322,240 422,240
CE Electric UK Funding Eurobonds ......................... 291,643 299,580
CE Electric UK Funding Company Senior Notes and
Sterling Bonds .......................................... 646,500 653,750
Yorkshire Electric Debt .................................. 1,491,597 --
CE Gas Loan .............................................. 70,180 73,162
Casecnan Notes and Bonds ................................. 320,138 346,439
Philippine Term Loans .................................... 313,221 392,625
Cordova Funding Senior Secured Bonds ..................... 225,000 225,000
Salton Sea Bonds ......................................... 139,896 140,528
MidAmerican Capital 8.52% Notes .......................... 23,333 46,667
HomeServices 7.12% Senior Notes and Other ................ 36,780 37,607
Other, including fair value adjustments .................. (6,292) (9,119)
---------- ----------
$5,071,991 $3,827,674
========== ==========

MIDAMERICAN FUNDING, LLC SENIOR NOTES AND BONDS

On March 11, 1999, MidAmerican Funding, LLC, a wholly owned subsidiary of the
Company, issued $200 million of 5.85% Senior Secured Notes due in 2001, $175
million of 6.339% Senior Secured Notes due in 2009, and $325 million of 6.927%
Senior Secured Bonds due in 2029. The proceeds from the offering were used to
complete the MidAmerican acquisition in 1999.

On March 1, 2001 MidAmerican Funding, LLC retired $200 million of 5.85% Senior
Secured Notes due 2001. On March 19, 2001 MidAmerican Funding, LLC issued $200
million of 6.75% Senior Secured Notes due March 1, 2011.

MIDAMERICAN ENERGY MORTGAGE BONDS, POLLUTION CONTROL BONDS AND NOTES

The components of MidAmerican Energy's Mortgage Bonds, Pollution Control Bonds
and Notes at December 31 are as follows (in thousands):

2001 2000
----------- -----------

Mortgage bonds:
7.125% Series, due 2003 ......... $100,000 $100,000
7.70% Series, due 2004 .......... 55,630 55,630
7% Series, due 2005 ............. 90,500 90,500
7.375% Series, due 2008 ......... 75,000 75,000
7.45% Series, due 2023 .......... 6,940 6,940
6.95% Series, due 2025 .......... 12,500 12,500
-------- --------
$340,570 $340,570
======== ========

F-37

2001 2000
----------- -----------

Pollution control revenue obligations:
5.75% Series, due periodically through 2003 ........................ $ 5,760 $ 7,200
5.95% Series, due 2023 (secured by general mortgage bonds) ......... 29,030 29,030
6.7% Series, due 2003 .............................................. 1,000 1,000
6.1% Series, due 2007 .............................................. 1,000 1,000
Variable rate series -
Due 2016 and 2017, 1.77% and 4.56% respectively .................. 37,600 37,600
Due 2023 (secured by general mortgage bond, 1.77%
and 4.56%, respectively) ........................................ 28,295 28,295
Due 2023, 1.77% and 4.56% respectively ........................... 6,850 6,850
Due 2024, 1.77% and 4.56% respectively ........................... 34,900 34,900
Due 2025, 1.77% and 4.56% respectively ........................... 12,750 12,750
-------- --------
$157,185 $158,625
======== ========
Notes:
8.75% Series, due 2002 ............................................. $ 240 $ 240
7.375% Series, due 2002 ............................................ 162,000 162,000
6.5% Series, due 2001 .............................................. -- 100,000
6.375% Series, due 2006 ............................................ 160,000 160,000
-------- --------
$322,240 $422,240
======== ========

CE ELECTRIC UK FUNDING EUROBONDS

The balances at December 31, 2001 and 2000 consists of the following (in
thousands):

2001 2000
----------- -----------

8.625% Bearer bonds due 2005 .......... $145,879 $149,865
8.875% Bearer bonds due 2020 .......... 145,764 149,715
-------- --------
$291,643 $299,580
======== ========

CE ELECTRIC UK FUNDING COMPANY SENIOR NOTES AND STERLING BONDS

The balances at December 31 are comprised of the following (in thousands):

2001 2000
----------- -----------

6.853% Senior Notes due 2004 ........... $124,613 $124,503
6.995% Senior Notes due 2007 ........... 235,937 235,804
7.25% Sterling Bonds due 2022 .......... 285,950 293,443
-------- --------
$646,500 $653,750
======== ========

The CE Electric UK Funding Company Senior Notes and Sterling Bonds prohibit
distributions to any of its stockholders unless certain financial ratios are met
by the CE Electric UK Funding Company or the long-term debt rating falls below a
prescribed level.

F-38

YORKSHIRE ELECTRIC DEBT

In connection with the Yorkshire/Northern supply swap on September 21, 2001, the
Company assumed approximately $1.5 billion in debt. The balance at December 31,
2001 is comprised of the following (in thousands):

2001
------------

9.250% Eurobond due 2020 .................. $ 383,576
7.250% Eurobond due 2028 .................. 311,427
Variable rate Trust Securities due 2020
(5.19% at December 31, 2001) ............. 235,313
8.080% Trust Securities due 2038 .......... 261,082
6.496% Yankee Bonds due 2008 .............. 300,199
----------
$1,491,597
==========

The Yorkshire Electric Debt prohibits distributions to any of its stockholders
unless certain financial ratios are met by Yorkshire or the long-term debt
rating falls below a prescribed level.

CE GAS LOAN

CE Gas borrowed $70.2 million and $73.2 million on a (pounds sterling)70 million
revolving facility at December 31, 2001 and 2000, respectively. The amount
carries a variable interest rate based on LIBOR (4.87% at December 31, 2001).
The revolving facility had utilized (pounds sterling)48.3 million and (pounds
sterling)49.0 million at December 31, 2001 and 2000, respectively.

CASECNAN NOTES AND BONDS

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

2001 2000
----------- -----------

Senior Secured Floating Rate Notes (FRNs)
due in 2002 ............................................. $ 23,638 $ 49,939
11.45% Senior Secured Series A Notes due in 2005 ......... 125,000 125,000
11.95% Senior Secured Series B Bonds due in 2010 ......... 171,500 171,500
-------- --------
$320,138 $346,439
======== ========

The Company held $3.0 million and $6.3 million of the FRNs at December 31, 2001
and 2000, respectively.

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

PHILIPPINE TERM LOANS

The Overseas Private Investment Corporation ("OPIC") provided term loan
financing for the Company's Malitbog geothermal power project of $46.8 million
that was fixed at an interest rate of 9.176%. A syndicate of international
commercial banks is providing term loan financing of $84.4 million at a variable
interest rate based on LIBOR (4.295% at December 31, 2001). The loans have
scheduled repayments through June 2005.

Export-Import Bank of the United States ("Ex-Im Bank") provided term loan
financing for the Company's Upper Mahiao geothermal power project of $121.3
million at a fixed interest rate of 5.95%. United Coconut Planters Bank of the
Philippines is providing term loan financing of $8.3 million at a variable
interest rate based on LIBOR (5.130% at December 31, 2001). The loans have
scheduled repayments through June 2006.

F-39

Ex-Im Bank provided term loan financing for the Company's Mahanagdong geothermal
power project of $154.6 million at a fixed rate of 6.92%. OPIC is providing term
loan financing of $34.3 million at a fixed interest rate of 7.6%. The loans have
scheduled repayments through June 2007.

CORDOVA FUNDING SENIOR SECURED BONDS

On September 10, 1999 Cordova Funding Corporation ("Cordova Funding"), a wholly
owned subsidiary of the Company, closed the $225 million aggregate principal
amount financing for the construction of the Cordova Project. The proceeds were
loaned to Cordova Energy and comprise the following (in thousands):

SERIES ISSUE DATE DUE DATE INTEREST RATE AMOUNT
- ------------------------------------------ -------------------- ---------- --------------- ----------

Series A-1 Senior Secured Bonds .......... September 10, 1999 2019 8.64% $ 93,515
Series A-2 Senior Secured Bonds .......... December 15, 1999 2019 8.79% 31,309
Series A-3 Senior Secured Bonds .......... March 15, 2000 2020 9.07% 29,300
Series A-4 Senior Secured Bonds .......... June 15, 2000 2020 8.82% 58,121
Series A-5 Senior Secured Bonds .......... September 15, 2000 2020 8.48% 12,755
--------
Total .................................... $225,000
========

MidAmerican Energy Holdings Company has guaranteed a specified portion of the
scheduled debt service on the Cordova Funding Senior Secured Bonds equal to $37
million.

SALTON SEA BONDS

Salton Sea Funding Corporation, an indirect wholly owned subsidiary of CE
Generation, had a debt balance of $520.3 million at December 31, 2001. CalEnergy
Minerals LLC is one of several guarantors of the Salton Sea Funding
Corporation's debt. As a result of a note allocation agreement, CalEnergy
Minerals LLC is primarily responsible for $139.9 million of the 7.475% Senior
Secured Series F Bonds due November 30, 2018. MidAmerican Energy Holdings
Company has guaranteed a specified portion of the scheduled debt service on the
Series F Bonds equal to this current principal amount of $139.9 million and
associated interest.

ANNUAL REPAYMENTS OF SUBSIDIARY AND PROJECT DEBT

The annual repayments of the subsidiary and project debt for the years beginning
January 1, 2002 and thereafter are as follows (in thousands):

MIDAMERICAN MIDAMERICAN
FUNDING, MIDAMERICAN ENERGY MIDAMERICAN CE ELECTRIC
LLC SENIOR ENERGY POLLUTION ENERGY AND HOME SALTON UK
NOTES AND MORTGAGE CONTROL CAPITAL SERVICES NOTES SEA FUNDING
BONDS BONDS BONDS NOTES AND OTHER BONDS EUROBONDS
------------- ------------- ------------ ------------- ---------------- ---------- ------------

2002 ........... $ -- $ -- $ 1,440 $185,573 $ 706 $ 2,108 $ --
2003 ........... -- 100,000 5,320 -- 583 1,405 --
2004 ........... -- 55,630 -- -- 5,133 1,757 --
2005 ........... -- 90,500 -- -- 5,048 1,756 145,879
2006 ........... -- -- -- 160,000 5,036 1,827 --
Thereafter ..... 700,000 94,440 150,425 -- 20,274 131,043 145,764
-------- -------- -------- -------- -------- -------- --------
$700,000 $340,570 $157,185 $345,573 $ 36,780 $139,896 $291,643
======== ======== ======== ======== ======== ======== ========

F-40

CE ELECTRIC UK CORDOVA
FUNDING COMPANY FUNDING
SENIOR NOTES CASECNAN PHILIPPINE SENIOR
AND STERLING YORKSHIRE CE NOTES AND TERM SECURED
BONDS ELECTRIC DEBT GAS LOAN BONDS LOANS BONDS TOTAL
----------------- --------------- ---------- ----------- ------------ ------------ ------------

2002 ............... $ -- $ -- $ 25,642 $ 32,214 $ 68,259 $ 1,238 $ 317,180
2003 ............... -- -- 13,050 41,467 72,148 9,000 242,973
2004 ............... 124,613 -- 16,897 49,360 67,148 8,100 328,638
2005 ............... -- -- 14,455 54,752 63,034 7,875 383,299
2006 ............... -- -- 136 36,015 30,037 4,500 237,551
Thereafter ......... 521,887 1,491,597 -- 106,330 12,595 194,287 3,568,642
--------- ---------- -------- --------- --------- --------- ----------
$ 646,500 $1,491,597 $ 70,180 $ 320,138 $ 313,221 $ 225,000 $5,078,283
========= ========== ======== ========= ========= ========= ==========

9. INCOME TAXES

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

MEHC (PREDECESSOR)
-----------------------------------
MARCH 14, 2000 JANUARY 1, 2000
YEAR ENDED THROUGH THROUGH YEAR ENDED
DECEMBER 31, 2001 DECEMBER 31, 2000 MARCH 13, 2000 DECEMBER 31, 1999
------------------- ------------------- ---------------- ------------------

Current:
State ........... $ 2,669 $ 10,527 $ (1,886) $ 7,337
Federal ......... 51,025 17,387 9,147 128,839
Foreign ......... 43,450 40,823 16,012 13,889
--------- --------- -------- ---------
97,144 68,737 23,273 150,065
--------- --------- -------- ---------

Deferred:
State ........... 22,095 (1,933) 834 1,791
Federal ......... (36,441) (32,469) 1,854 (75,510)
Foreign ......... 167,266 18,942 5,047 17,129
--------- --------- -------- ---------
152,920 (15,460) 7,735 (56,590)
--------- --------- -------- ---------
Total ............ $ 250,064 $ 53,277 $ 31,008 $ 93,475
========= ========= ======== =========

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

Federal statutory rate ................................ 35.0% 35.0% 35.0% 35.0%
Investment and energy tax credits ..................... (1.0) (2.3) (.7) (1.8)
State taxes, net of federal tax effect ................ 3.2 2.6 (.8) 1.7
Goodwill amortization ................................. 5.9 12.1 5.9 5.5
Dividends on preferred securities of subsidiary
trusts* .............................................. (6.1) (11.1) (2.8) (3.8)
Tax effect of foreign income .......................... (2.5) (5.8) (5.0) .3
Non-recurring items on CE Electric UK
Funding, net of tax effect of foreign income ......... 19.2 -- -- --
Non-recurring items on Indonesia ...................... -- -- -- (11.0)
Dividends received deduction .......................... (2.6) (6.8) (1.0) (3.7)
Other items, net ...................................... (1.5) .6 3.4 3.9
---- ----- ---- -----
Effective tax rate .................................... 49.6% 24.3% 34.0% 26.1%
==== ===== ==== =====

- ----------

* Dividends on preferred securities of subsidiary trusts are included in
minority interest.

F-41

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

2001 2000
------------- -------------

Property, plant, contracts and equipment .................... $1,245,140 $ 866,678
Income taxes recoverable through future rates ............... 185,222 186,427
Fuel cost recoveries ........................................ 20,272 14,598
Reacquired debt ............................................. 7,544 10,256
---------- ----------
1,458,178 1,077,959
---------- ----------
Nuclear reserve and decommissioning ......................... (17,898) (20,690)
Deferred income ............................................. (24,732) (8,883)
Deferred contract costs ..................................... (65,145) (51,703)
Revenue sharing accruals .................................... (24,769) (3,742)
Accruals not currently deductible for tax purposes .......... (35,221) (40,563)
Other ....................................................... (6,145) (7,350)
---------- ----------
(173,910) (132,931)
---------- ----------
Net deferred income taxes ................................... $1,284,268 $ 945,028
========== ==========

10. COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY
TRUSTS

The Company has organized special purpose Delaware business trusts
(collectively, the "Trusts") pursuant to their respective amended and restated
declarations of trusts (collectively, the "Declarations"). The Company, through
these Trusts, issued Company-obligated mandatorily redeemable preferred
securities (collectively, the "Trust Securities") as follows (in thousands):

ORIGINAL CARRYING VALUE CARRYING VALUE
ISSUE DECEMBER 31, DECEMBER 31, CONVERSION
ISSUER ISSUE DATE RATE AMOUNT 2001 2000 RATE
- ------------------------------------- ------------------- ---------- ---------- ---------------- --------------- -----------

CalEnergy Capital Trust II .......... February 26, 1997 6.25% $180,000 $ 155,584 $ 156,084 1.1655
CalEnergy Capital Trust III ......... August 12, 1997 6.50% 270,000 269,984 269,984 1.047
MidAmerican Capital Trust I
(issued to Berkshire) .............. March 14, 2000 11.00% 454,772 454,772 454,772 N/A
Fair value adjustment ............... (92,189) (94,317)
--------- ---------
$ 788,151 $ 786,523
========= =========

During 2001 and 2000, CalEnergy Capital Trust II redeemed 10,000 and 477,000
shares, respectively, of preferred securities at an aggregate cost of
approximately $.4 million and $19.5 million, respectively.

The Company owns all of the common securities of the Trusts. The Trust
Securities have a liquidation preference of fifty dollars each and represent
undivided beneficial ownership interests in each of the Trusts. The assets of
the Trusts consist solely of the Company's Subordinated Debentures due February
25, 2012, September 1, 2027, and March 14, 2010, respectively, in outstanding
aggregate principal amounts of approximately $155.5 million, $270 million and
$454.8 million, respectively (collectively, the "Junior Debentures") issued
pursuant to their respective indentures. The indentures include agreements by
the Company to pay expenses and obligations incurred by the Trusts.

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

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

F-42

Pursuant to Preferred Securities Guarantee Agreements (collectively, the
"Guarantees"), between the Company and a preferred guarantee trustee, the
Company has agreed irrevocably to pay to the holders of the Trust Securities, to
the extent that the Trustee has funds available to make such payments, quarterly
distributions, redemption payments and liquidation payments on the Trust
Securities. Considered together, the undertakings contained in the Declarations,
Junior Debentures, Indentures and Guarantees constitute full and unconditional
guarantees by the Company of the Trusts' obligations under the Trust Securities.

11. SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST

In December 1996, MidAmerican Energy Financing I, a wholly owned statutory
business trust of MidAmerican Energy, issued 4,000,000 shares of 7.98% Series
MidAmerican Energy-obligated mandatorily redeemable preferred securities. The
sole assets of MidAmerican Energy Financing are $103.1 million of MidAmerican
Energy 7.98% Series A Debentures due 2045 (the "Debentures"). There is a full
and unconditional guarantee by MidAmerican Energy of MidAmerican Energy
Financing's obligations under the preferred securities. MidAmerican Energy has
the right to defer payments of interest on the Debentures by extending the
interest payment period for up to 20 consecutive quarters. If interest payments
on the Debentures are deferred, distributions on the preferred securities will
also be deferred. During any deferral, distributions will continue to accrue
with interest thereon, and MidAmerican Energy may not declare or pay any
dividend or other distribution on, or redeem or purchase, any of its capital
stock.

If the Debentures, or a portion thereof, are redeemed, MidAmerican Energy
Financing must redeem a like amount of the preferred securities. If a
termination of MidAmerican Energy Financing occurs, MidAmerican Energy Financing
will distribute to the holders of the preferred securities a like amount of the
Debentures unless such a distribution is determined not to be practicable. If a
determination is made, the holders of the preferred securities will be entitled
to receive, out of the assets of MidAmerican Energy Financing after satisfaction
of its liabilities, a liquidation amount of $25 for each preferred security held
plus accrued and unpaid distributions. See Note 21.

12. PREFERRED STOCK

In connection with the Teton Transaction, the Company issued 34.6 million shares
of no par, zero coupon convertible preferred stock valued at $1,211.4 million.
Each share of preferred stock is convertible at the option of the holder into
one share of the Company's common stock subject to certain adjustments as
described in the Company's Amended and Restated Articles of Incorporation

13. STOCK OPTIONS

The Company had various stock option plans under which shares were reserved for
grant as incentive or non-qualified stock options, as determined by the Board of
Directors. The plans allowed options to be granted at 85% of their fair market
value of the common stock at the date of grant. Generally, options were issued
at 100% of fair market value of the common stock at the date of grant. Options
granted under the 1996 plan became exercisable over a period of two to five
years and expired if not exercised within ten years from the date of grant or,
in some instances, a lesser term.

As a result of the Teton Transaction, the majority of the options were cashed
out at $35.05 per share. The remaining options of 2,145,000 were reissued under
the new MidAmerican Energy Holdings Company and an additional 703,329 options
were issued. The old options are fully vested and the additional options vest
monthly over three years. The options are exercisable until the end of the term
on March 14, 2008 at exercise prices ranging from $15.94 to $35.05 per share.

14. FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of a financial instrument is the amount at which the instrument
could be exchanged in a current transaction between willing parties, other than
in a forced sale or liquidation. Although

F-43

management uses its best judgment in estimating the fair value of these
financial instruments, there are inherent limitations in any estimation
technique. Therefore, the fair value estimates presented herein are not
necessarily indicative of the amounts that the Company could realize in a
current transaction.

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

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

Debt instruments -- The fair value of all debt issues listed on exchanges has
been estimated based on the quoted market prices. The Company is unable to
estimate a fair value for the Philippine term loans as there are no quoted
market prices available.

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

2001 2000
--------------------------- --------------------------
ESTIMATED ESTIMATED
PRINCIPAL FAIR PRINCIPAL FAIR
AMOUNT VALUE AMOUNT VALUE
------------ ------------ ----------- ------------
(IN THOUSANDS)

7.63% Senior Notes ................................. $ 350,000 $ 362,425 $ 350,000 $ 360,115
6.96% Senior Notes ................................. 215,000 222,676 215,000 216,570
7.23% Senior Notes ................................. 260,000 268,684 260,000 264,004
7.52% Senior Notes ................................. 450,000 455,085 450,000 459,090
8.48% Senior Notes ................................. 475,000 478,325 475,000 507,918
7.52% Senior Notes ................................. 101,680 102,130 101,888 102,020
MidAmerican Funding, LLC Senior Notes and
Bonds ............................................. 700,000 667,402 700,000 657,300
MidAmerican Energy Mortgage Bonds .................. 340,570 356,087 340,570 345,692
MidAmerican Energy Pollution Control Bonds ......... 157,185 157,672 158,625 158,914
MidAmerican Energy Notes ........................... 322,240 329,573 422,240 420,496
MidAmerican Capital Notes .......................... 23,333 23,849 46,667 46,464
HomeServices Senior Notes and Other ................ 36,780 31,143 37,607 34,094
Salton Sea Bonds ................................... 139,896 121,290 140,528 116,947
CE Electric UK Funding Eurobonds ................... 291,643 346,115 299,580 357,456
CE Electric UK Funding Company Senior
Notes and Sterling Bonds .......................... 646,500 702,643 653,750 694,031
Yorkshire Electric Debt ............................ 1,491,597 1,482,870 -- --
Casecnan Notes and Bonds ........................... 320,138 291,517 346,439 319,056
Cordova Funding Senior Secured Bonds ............... 225,000 227,442 225,000 224,018
CE Gas Loan ........................................ 70,180 70,180 73,162 73,162
Company-obligated preferred securities of
subsidiary trusts ................................. 880,340 801,722 880,840 769,605
Subsidiary-obligated preferred securities of
subsidiary trusts ................................. 100,000 99,640 100,000 98,752
Preferred Securities of Subsidiaries ............... 121,183 107,893 145,686 131,255

INTEREST RATE RISK

At December 31, 2001, the Company had fixed-rate long-term debt,
Company-obligated mandatorily redeemable preferred securities of subsidiary
trusts, and subsidiary-obligated mandatorily redeemable preferred securities of
subsidiary trusts of $7,678.0 million in principal amount and having a fair
value of $7,808.2 million. These instruments are fixed-rate and therefore do not
expose the Company to the risk of earnings loss due to changes in market
interest rates. However, the fair value of these instruments would decrease by
approximately $355.7 million if interest rates were to increase by 10% from
their levels

F-44

at December 31, 2001. In general, such a decrease in fair value would impact
earnings and cash flows only if the Company were to reacquire all or a portion
of these instruments prior to their maturity.

At December 31, 2001, the Company had floating-rate obligations of $281.4
million that expose the Company to the risk of increased interest expense in the
event of increases in short-term interest rates. These obligations are not
hedged. If the floating rates were to increase by 10% from December 31, 2001
levels, the Company's consolidated interest expense for unhedged floating-rate
obligations would increase by approximately $75,000 each month in which such
increase continued based upon December 31, 2001 principal balances.

F-45

The amortized cost, gross unrealized gain and losses and estimated fair value of
investments in debt and equity securities at December 31 are as follows (in
thousands):

2001
------------------------------------------------------
AMORTIZED UNREALIZED UNREALIZED FAIR
COST GAINS LOSSES VALUE
----------- ------------ ------------ ----------

Available-for-sale:
Equity securities ................... $ 53,663 $24,444 $ (3,144) $ 74,963
Municipal bonds ..................... 27,842 1,315 (92) 29,065
U. S. Government securities ......... 26,725 1,910 (19) 28,616
Corporate securities ................ 18,682 812 (23) 19,471
Cash equivalents .................... 7,120 -- -- 7,120
-------- ------- -------- --------
$134,032 $28,481 $ (3,278) $159,235
======== ======= ======== ========
Held-to-Maturity:
Debt Securities ..................... $ 2,074 $ -- $ -- $ 2,074
U.S. Treasury Strips ................ 1,090 85 -- 1,175
Agency Obligations .................. 611 -- (22) 589
-------- ------- -------- --------
$ 3,775 $ 85 $ (22) $ 3,838
======== ======= ======== ========

2000
-------------------------------------------------------
AMORTIZED UNREALIZED UNREALIZED FAIR
COST GAINS LOSSES VALUE
----------- ------------ ------------ -----------

Available-for-sale:
Equity securities ................... $ 83,509 $34,110 $ (7,115) $110,504
Municipal bonds ..................... 27,758 1,071 (175) 28,654
U. S. Government securities ......... 26,284 1,163 -- 27,447
Corporate securities ................ 25,737 48 (1,027) 24,758
Cash equivalents .................... 11,150 -- -- 11,150
-------- ------- -------- --------
$174,438 $36,392 $ (8,317) $202,513
======== ======= ======== ========
Held-to-Maturity:
Debt Securities ..................... $ 2,077 $ -- $ -- $ 2,077
U.S. Treasury Strips ................ 677 80 -- 757
Agency Obligations .................. 571 -- (53) 518
-------- ------- -------- --------
$ 3,325 $ 80 $ (53) $ 3,352
======== ======= ======== ========

At December 31, 2001, the debt securities held by the Company had the following
maturities (in thousands):

AVAILABLE FOR SALE HELD TO MATURITY
----------------------- ----------------------
AMORTIZED FAIR AMORTIZED FAIR
COST VALUE COST VALUE
----------- --------- ----------- --------

Within 1 year .............. $ 3,269 $ 3,332 $ 3 $ 3
1 through 5 years .......... 28,851 30,706 2,323 2,357
5 through 10 years ......... 10,733 11,578 1,449 1,478
Over 10 years .............. 30,396 31,536 -- --

F-46

The proceeds and gross realized gains and losses on the disposition of
available-for-sale and held-to-maturity investments are shown in the following
table (in thousands). Realized gains and losses are determined by specific
identification.

MEHC (PREDECESSOR)
-----------------------------------
MARCH 14, 2000 JANUARY 1, 2000
YEAR ENDED THROUGH THROUGH YEAR ENDED
DECEMBER 31, 2001 DECEMBER 31, 2000 MARCH 13, 2001 DECEMBER 31, 1999
------------------- ------------------- ---------------- ------------------

Proceeds from sales ........... $ 68,333 $ 93,531 $ 22,588 $617,262
Gross realized gains .......... 2,676 6,464 1,560 97,545
Gross realized losses ......... (7,314) (10,585) (2,556) (6,437)

15. NON-RECURRING ITEMS

TEESSIDE

In December 2001, the Company recorded a non-recurring charge of $20.7 million
representing an asset valuation impairment charge under SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets," relating to the Company's
15.4% interest in Teesside Power Ltd. ("Teesside"). Teesside owns and operates
an 1,875 MW combined cycle gas-fired power plant. Enron Corp. ("Enron"), through
its subsidiaries, owned a 42.5% interest, operated the plant, and purchased
668MW of capacity. Enron's subsidiary, who owns and operates Teesside, is now in
administration and administrators have been appointed to run its business and
are attempting to find a buyer. As a result of Enron's subsidiary being in
administration, Teesside is in discussion with its lenders over restructuring of
the (pounds sterling)650 million debt still outstanding. It is anticipated that
there will be no further dividends arising from the investment in Teesside and
subsequently, the Company has determined the investment in Teesside to be of
negligible value.

TELEPHONE FLAT SALE

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

WESTERN STATES SALE

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

QUALIFIED FACILITIES DISPOSITIONS

On February 26, 1999, the Company closed the sale of all of its indirect
ownership interests in the Coso Joint Ventures ("Coso") to Caithness Energy LLC
("Caithness") for $205 million in cash. On March 3, 1999, the Company closed the
sale of 50% of its ownership interests in CE Generation to an affiliate of El
Paso Energy Corporation for an aggregate consideration of approximately $245
million in cash, $6.5 million in contingent payments and $23.5 million in equity
commitments. The sales of the qualified facilities resulted in a net
non-recurring pre-tax gain of $20.2 million and an after-tax gain of
approximately $12.4 million.

MCLEOD

On May 18, 1999, the Company announced the sale of approximately 6.74 million
shares of McLeodUSA ("McLeod") Class A common stock, through a secondary
offering by McLeod, at $55.625 per share. Proceeds from the sale were
approximately $375 million, with a resulting pre-tax gain to the Company of
approximately $78.2 million, and an after-tax gain of approximately $47.1
million.

F-47

INDONESIA

On December 2, 1994, former subsidiaries of the Company, Himpurna California
Energy Ltd. ("HCE") and Patuha Power, Ltd. ("PPL", together with HCE, the
"Indonesian Subsidiaries") executed separate joint operation contracts for the
development of geothermal steam fields and geothermal power facilities located
in Central Java in Indonesia.

In 1997 and 1998 a series of Indonesian government decrees and other actions
created significant uncertainty as to whether the Indonesian government would
honor their contractual obligations to the Indonesian Subsidiaries. In 1997, the
Company recorded a non-recurring charge of $87 million representing an asset
valuation impairment charge under SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets," relating to the Company's assets in Indonesia. The charge
of $87 million represented the amount by which the carrying amount of such
assets exceeded the estimated fair value of the assets determined by discounting
the expected future net cash flows of the Indonesia projects.

The Company carried political risk insurance on its investment in HCE and PPL
through OPIC, an agency of the U.S. Government, as well as through private
market insurers. On November 18, 1999, the Company transferred the Indonesian
Subsidiaries to OPIC and received payment from OPIC and the private market
insurers totaling $290 million under its political risk insurance policies,
reflecting the return of its equity investment less policy deductibles. Due
primarily to the timing of the receipt of proceeds, the Company recorded a
pre-tax gain of approximately $40.3 million on the insurance proceeds and an
additional tax benefit of $17.7 million for an after-tax gain of $58.0 million.

On September 13, 2001, the Company transferred shares of Bali Energy Ltd., an
indirect wholly owned Indonesian subsidiary of the Company, to PT Tenaga Burni
Bali. The Company recorded a pre-tax gain of $10.4 million and an after-tax gain
of $6.5 million on the transfer of the shares.

16. ACCOUNTING FOR DERIVATIVES

INTEREST RATE RISK

MidAmerican Energy has entered into a two-year, $162 million fixed-to-floating
interest rate swap agreement in conjunction with its $162 million, 7.375% series
of medium-term notes due August 1, 2002. The floating rate of the swap is based
on a three-month LIBOR rate and the effective interest rate after the swap was
4.46% in 2001. As of December 31, 2001, the fair value of this swap was $9.1
million.

CURRENCY EXCHANGE RATE RISK

CE Electric UK Funding entered into certain currency rate swap agreements for
the CE Electric UK Funding Company Senior Notes with two large multi-national
financial institutions. The swap agreements effectively convert the U.S. dollar
fixed interest rate to a fixed rate in Sterling. For the $125 million of 6.853%
Senior Notes, the agreements extend until December 30, 2004 and convert the U.S.
dollar interest rate to a fixed Sterling rate of 7.744%. For the $237 million of
6.995% Senior Notes, the agreements extend until December 30, 2007 and convert
the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated
fair value of these swap agreements at December 31, 2001 is approximately $44.8
million based on quotes from the counterparty to these instruments and
represents the estimated amount that the Company would expect to receive if
these agreements were terminated. It is the Company's intention to hold these
swap agreements to maturity.

Yorkshire entered into certain currency rate swap agreements for the Trust
Securities and the Yankee Bonds with five large multi-national financial
institutions. The swap agreements effectively convert the U.S. dollar fixed
interest rate to a fixed rate in Sterling. For the $255 million of Trust
Securities, the agreements extend until June 30, 2008 and convert the U.S.
dollar interest rate to a fixed Sterling rate ranging from 9.4758% to 9.715%.
For the $300 million of Yankee Bonds, the agreements extend until February 25,
2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging
from 7.3175% to 7.345%. The estimated fair value of these swap agreements at
December 31, 2001 is approximately $8.4 million based on quotes from the
counterparty to these instruments and represents the estimated amount that the
Company would expect to receive if these agreements were terminated. It is the
Company's intention to hold these swap agreements to maturity.

F-48

A decrease of 10% in the December 31, 2001 rate of exchange of Sterling to
dollars would increase the amount received if these swap agreements were
terminated by approximately $106.4 million.

ENERGY COMMODITY PRICE RISK

Under the current regulatory framework, MidAmerican Energy is allowed to recover
in revenues the cost of gas sold from all of its regulated gas customers through
a purchased gas adjustment clause. Because the majority of MidAmerican Energy's
firm natural gas supply contracts contain pricing provisions based on a daily or
monthly market index, MidAmerican Energy's regulated gas customers, although
ensured of the availability of gas supplies, retain the risk associated with
market price volatility.

MidAmerican Energy enters into natural gas futures and swap agreements to
mitigate a portion of the market risk retained by its regulated gas customers
through the purchased gas adjustment clause. These financial derivative
activities are recorded as hedge accounting transactions, with net amounts
exchanged or accrued under swap agreements and realized gains or loses on
futures contracts included in the cost of gas sold and recovered in revenues
from regulated gas customers.

MidAmerican Energy also derives revenues from nonregulated sales of natural gas.
Pricing provisions are individually negotiated with these customers and may
include fixed prices or prices based on a daily or monthly market index.
MidAmerican Energy enters into natural gas futures and swap agreements to offset
the financial impact of variations in natural gas commodity prices for physical
delivery to nonregulated customers. These financial derivative activities are
also recorded as hedge accounting transactions.

MidAmerican Energy uses natural gas derivative instruments for trading purposes
pursuant to EITF 98-10 under strict value-at-risk guidelines outlined by senior
management. Derivative instruments held for trading purposes are recorded at
fair value and any unrealized gains or losses are reported in earnings. Trading
revenues and costs are reported gross on the consolidated statements of
operations.

MidAmerican Energy is exposed to variations in the price of fuel for generation
and the price of purchased power in its Iowa jurisdiction comprising 89% of 2001
electric operating revenues. Fuel price risk is mitigated through forward
contracts. Under typical operating conditions, MidAmerican Energy has sufficient
generation to supply its retail electric needs. A loss of such generation at a
time of high market prices could subject MidAmerican Energy to losses on its
energy sales. MidAmerican Energy uses electricity forward contracts to hedge
anticipated sales of wholesale electric power.

MidAmerican Energy and its customers are exposed to the effect of variations in
weather conditions on sales and purchased, respectively, of electricity and
natural gas. For the 2001-2002 heating season, MidAmerican Energy entered into
several degree-day swaps to offset a portion of the financial impact of those
variations on MidAmerican Energy and its customers.

MidAmerican Energy had the following financial derivative instruments for its
natural gas and electric operations as of December 31:

F-49

MidAmerican Energy derivative instruments used for other than trading purposes--

2001 2000
----------------------- -------------------

Natural Gas Futures Contracts -- NYMEX:
Net Contract Volumes -- Long (Short) ......... (600,000) MMBtu 1,460,000 MMBtu
Unrealized Gain, in thousands ................ $ 40 $ 7,554
Weighted Average Settlement Price ............ $ (6.77) $ 9.42

Natural Gas Swap Contracts:
Contract Volumes -- Pay Fixed ................ 7,853,052 MMBtu 13,496,239 MMBtu
Contract Volumes -- Receive Fixed ............ 900,000 MMBtu 10,610,741 MMBtu
Unrealized Gain (Loss), in thousands ......... $(7,643) $ 8,055
Weighted Average Pay Fixed Price ............. $ (0.97) $ 0.89
Weighted Average Receive Fixed Price ......... $ 0.04 $ (0.37)

Natural Gas Options:
Contract Volumes -- Long ..................... 2,300,000 MMBtu 1,790,280 MMBtu
Unrealized Gain (Loss), in thousands ......... $(1,212) $ 953

Degree Day Swap Contracts:
Contract Volumes -- Long ..................... 20,000 $/Degree day -- $/Degree Day
Unrealized Gain (Loss), in thousands ......... $(3,486) $ --

Electric Forward Contracts:
Contract Volumes -- (Short) .................. (728,800) MWh (139,200) MWh
Unrealized Gain (Loss), in thousands ......... $ 6,313 $(4,731)

A $1.00 decrease in underlying natural gas prices would decrease unrealized
gains on the futures contracts held at December 31, 2001, by approximately $0.6
million and would decrease unrealized losses on the above swap contracts by
approximately $7.0 million. A $5.00 increase in underlying electricity prices
would decrease unrealized gains on the forward contracts held at December 31,
2001, by approximately $3.6 million. The weighted average maturity for all
derivative instruments used for hedging purposes is under one year.

Unrealized gains and losses on cash flow hedges of future transactions are
recorded in other comprehensive income. Only hedges that are highly effective in
offsetting the risk of variability in future cash flows are accounted for in
this manner. Future transactions include purchases of gas for resale to
regulated and nonregulated customers, purchases of gas for storage, and
purchases and sales of wholesale electric energy. When the associated hedged
future transaction occurs or if a hedging relationship is no longer appropriate,
the unrealized gains and losses are reversed from other comprehensive income and
recognized in net income. Realized gains on cash flow hedges are recorded in
either cost of sales or operating revenues, depending upon the nature of the
physical transaction being hedged.

For 2001, a net loss of $408,000 and a net gain of $36,000, representing the
ineffectiveness of cash flow hedges, are reflected in cost of sales. During the
twelve months beginning January 1, 2002, it is anticipated that $3.4 million of
the $3.5 million after-tax, net unrealized gains on cash flow hedges presently
recorded as accumulated other comprehensive income will be realized and recorded
in earnings. MidAmerican Energy has hedged a portion of its exposure to the
variability of cash flows for future transactions through December 2003.

Unrealized gains and losses on fair value hedges are recognized in income as
either operating revenues or cost of sales depending upon the nature of the item
being hedged. Purchase and sales commitments hedged by fair value hedges are
recorded at fair value, with the changes in values also recognized in income and
substantially offsetting the impact of the hedges on earnings. For 2001, a net
pre-tax gain of $18,000, representing the ineffectiveness of fair value hedges,
is included in operating revenues.

F-50

MidAmerican Energy derivative instruments used for trading purposes--

2001 2000
-------------------- -------------------

Natural Gas Futures Contracts -- NYMEX:
Net Contract Volumes -- (Short) .............. 120,000 MMBtu (20,000) MMBtu
Unrealized (Loss), in thousands .............. $ (224) $ (79)
Weighted Average Settlement Price ............ $ 1.69 $(15.92)
Natural Gas Swap Contracts:
Contract Volumes -- Pay Fixed ................ 17,519,581 MMBtu 1,000,000 MMBtu
Contract Volumes -- Receive Fixed ............ 17,850,372 MMBtu 1,010,000 MMBtu
Unrealized Gain (Loss), in thousands ......... $2,045 $ (261)
Weighted Average Pay Fixed Price ............. $(0.99) $ 0.92
Weighted Average Receive Fixed Price ......... $ 1.09 $ (1.17)

A change in underlying natural gas prices would not materially affect unrealized
losses on the above future and swap contracts.

17. SECURITIZATION OF ACCOUNTS RECEIVABLE

In December 1998, CE Electric UK Funding entered into a revolving receivable
purchase agreement with Kitty Hawk Funding Corporation ("Kitty Hawk"), an
unaffiliated special purpose entity established to purchase accounts receivable.
In October 2000, the facility was transferred to Mont Blanc Capital Corp,
administered by ING Barings, which allowed CE Electric UK Funding to sell all of
its rights, title and interest in the majority of its billed electricity
accounts receivable and to borrow against its unbilled electricity accounts
receivable. In March 1999, CE Electric UK Funding received $161 million in cash
associated with the agreement. In connection with the Northern Supply/Yorkshire
swap on September 21, 2001, CE Electric UK Funding repaid the outstanding
balance of this purchase agreement and ended their arrangement with Mont Blanc
Capital Corp. CE Electric UK Funding does not have any amounts outstanding at
December 31, 2001.

In 1997, MidAmerican Energy entered into a revolving agreement, which expires in
October 2002, to sell all of its right, title and interest in the majority of
its billed accounts receivable to MidAmerican Energy Funding Corporation, a
special purpose entity established to purchase accounts receivable from
MidAmerican Energy. MidAmerican Energy Funding Corporation in turn sells
receivable interests to outside investors. In consideration of the sale,
MidAmerican Energy received cash and a subordinated note, bearing interest at
8%, from MidAmerican Energy Funding Corporation. As of December 31, 2001, the
revolving cash balance was $44 million, down $26 million from December 31, 2000,
and the amount outstanding under the subordinated note was $28.7 million. The
agreement is structured as a true sale under which the creditors or MidAmerican
Energy Funding Corporation will be entitled to be satisfied out of the assets of
MidAmerican Energy Funding Corporation prior to any value being returned to
MidAmerican Energy or its creditors. Therefore, the accounts receivable sold are
not reflected on the consolidated balance sheets. At December 31, 2001, $71.5
million of accounts receivable, net of reserves, was sold under the agreement.

18. REGULATORY MATTERS

CE ELECTRIC UK FUNDING

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

F-51

customers connected and the voltage at which customers receive the units of
electricity distributed. This formula determines the maximum average price per
unit of electricity distributed (in pence per kilowatt hour) which a DLH is
entitled to charge. The distribution price control formula permits DLHs to
receive additional revenues due to increased distribution of units and a
predetermined increase in customer numbers. The price control does not seek to
constrain the profits of a DLH from year to year. It is a control on revenue
that operates independently of most of the DLH's costs. During the lifetime of
the price control, additional cost savings therefore contribute directly to
profit.

MIDAMERICAN ENERGY

In 1997, pursuant to a rate proceeding before the Iowa Utilities Board ("IUB"),
MidAmerican Energy, the Office of Consumer Advocate and other parties entered
into a pricing plan settlement agreement establishing MidAmerican Energy's Iowa
retail electric rates. That settlement agreement expired on December 31, 2000.

On March 14, 2001, the Office of the Consumer Advocate filed a petition with the
IUB to reduce Iowa retail electric rates by approximately $77 million annually.
On June 11, 2001, MidAmerican Energy responded to that petition by filing a
request with the IUB to increase MidAmerican Energy's Iowa retail electric rates
by $51 million annually. On December 21, 2001, the IUB approved a settlement
agreement that freezes the rates in effect on December 31, 2000, through
December 31, 2005, and, with modifications, reinstates the revenue sharing
provisions of the 1997 pricing plan settlement agreement. Under the 2001
settlement agreement, an amount equal to 50% of revenues associated with returns
on equity between 12% and 14%, and 83.33% of revenues associated with returns on
equity above 14%, in each year will be recorded as a regulatory liability to be
used to offset a portion of the cost of future generating plant investments. An
amount equal to the regulatory liability will be recorded as depreciation
expense. As of December 31, 2001, MidAmerican Energy has recorded a $47.1
million regulatory liability that is reflected in other long-term accrued
liabilities on the consolidated balance sheet.

Under an Illinois restructuring law enacted in 1997, a sharing mechanism is in
place for MidAmerican Energy's Illinois regulated retail electric operations
whereby earnings above a computed threshold will be shared equally between
customers and shareholders. A two-year average return on common equity greater
than a two-year average benchmark will trigger an equal sharing of earnings on
the excess. MidAmerican Energy's computed level of return on common equity is
based on a rolling two-year average of the 30-year Treasury bond rates plus a
premium of 5.50% for 1998 and 1999 and a premium of 8.5% for 200 through 2004.
The two-year average above which sharing must occur for 2001 was 14.33%. The law
allows MidAmerican Energy to mitigate the sharing of earnings above the
threshold return on common equity through accelerated recovery of regulatory
assets.

On September 21, 2001, MidAmerican Energy filed a petition with the South Dakota
Public Utilities Commission ("SDPUC") to increase its South Dakota natural gas
rates. On February 20, 2002, the SDPUC approved a settlement agreement allowing
increased rates of $3.1 million annually.

On October 19, 2001, MidAmerican Energy filed a petition with the Illinois
Commerce Commission to increase its Illinois natural gas rates by $3.2 million
annually. A final decision on the petition is required within eleven months of
the date of filing.

19. PENSION COMMITMENTS

UNITED KINGDOM OPERATIONS

CE Electric UK Funding participates in the Electricity Supply Pension Scheme,
which provides pension and other related defined benefits, based on final
pensionable pay, to substantially all employees throughout the Electricity
Supply Industry in the United Kingdom.

F-52

The actuarial computation for December 31, 2001, 2000 and 1999 assumed interest
rates of 5.75%, 6.0% and 6.0% respectively, an expected return on plan assets of
7.0%, 6.5% and 6.5%, respectively, and annual compensation increases of 2.5%,
3.0% and 3.0%, respectively, over the remaining service lives of employees
covered under the plan. Amounts funded to the pension are primarily invested in
equity and fixed income securities.

The following table details the funded status and the amount recognized in the
Company's consolidated balance sheets for CE Electric UK Funding's plan as of
December 31, 2001 and 2000 (in thousands):

2001 2000
------------- ------------

Change in benefit obligation:
Benefit obligation at beginning of year .................... $ 951,553 $ 940,600
Service cost ............................................... 7,854 8,660
Interest cost .............................................. 51,926 50,765
Participant contributions .................................. 5,236 4,927
Benefits paid .............................................. (49,453) (49,272)
FAS 88 curtailment ......................................... 7,127 6,570
Northern Supply/Yorkshire swap net effect .................. 44,216 --
Experience gain and change of assumptions .................. (44,381) (10,697)
---------- ----------
Benefit obligation at end of the year ...................... 974,078 951,553
---------- ----------
Change in plan assets:
Fair value of plan assets at beginning of the year ......... 1,166,111 1,283,600
Actual return on plan assets ............................... (98,799) (73,741)
Net asset transfer resulting from Northern
Supply/Yorkshire Swap .................................... 46,980 --
Employer contributions ..................................... 582 597
Participant contributions .................................. 5,236 4,927
Benefits paid .............................................. (49,453) (49,272)
---------- ----------
Fair value of plan assets at end of the year ............... 1,070,657 1,166,111
---------- ----------
Funded status .............................................. 96,579 214,558
Unrecognized net loss ...................................... (196,648) (77,193)
---------- ----------
Prepaid benefit cost ....................................... $ 293,227 $ 291,751
========== ==========

Net periodic pension cost (benefit) for CE Electric UK Funding's plan for 2001,
2000 and 1999 included the following components (in thousands):

MEHC (PREDECESSOR)
-----------------------------
MARCH 14, 2000 JANUARY 1, 2000
THROUGH THROUGH
2001 DECEMBER 31, 2000 MARCH 31, 2000 1999
------------ ------------------- ---------------- ------------

Service cost -- benefits earned during the period..... $ 7,854 $ 6,933 $ 1,727 $ 10,200
Interest cost on projected benefit obligation ........ 51,926 40,640 10,125 48,500
Expected return on plan assets ....................... (78,979) (50,800) (12,657) (59,500)
Curtailment loss ..................................... 7,127 5,260 1,310 38,300
--------- --------- --------- ---------
Net periodic pension (benefit) cost .................. $ (12,072) $ 2,033 $ 505 $ 37,500
========= ========= ========= =========

As a result of the distribution price reviews in 1999, CE Electric UK Funding
implemented a review of staffing requirements primarily in its distribution
business. Following discussions with the trade unions, CE Electric UK Funding
put in place a workforce reduction program. In 1999, the Company recorded a
non-recurring pre-tax loss of approximately $47.7 million that included a
pension curtailment of $38.3 million. In 2000, the pension curtailment related
to this workforce reduction program was $6.6 million. The curtailment loss in
2001 of $7.1 million is a result of the Northern Supply/Yorkshire swap.

F-53

DOMESTIC OPERATIONS

The Company has primarily noncontributory cash balance defined benefit pension
plans covering substantially all domestic employees. Benefit obligations under
the plans are based on participants' compensation, years of service and age at
retirement. Funding is based upon the actuarially determined costs of the plans
and the requirements of the Internal Revenue Code and the Employee Retirement
Income Security Act. The Company has been allowed to recover pension costs
related to its employees in rates.

MidAmerican Energy currently provides certain postretirement health care and
life insurance benefits for retired employees. Under the plans, substantially
all of MidAmerican Energy's employees may become eligible for these benefits if
they reach retirement age while working for MidAmerican Energy. However,
MidAmerican Energy retains the right to change these benefits anytime at its
discretion. MidAmerican Energy expenses postretirement benefit costs on an
accrual basis and includes provisions for such costs in rates.

In 1999, the noncontributory cash balance defined benefit pension plans, the
noncontributory, nonqualified supplemental executive retirement plan, and the
postretirement plans were amended to include participants from the Company.
Prior to the amendment, these plans included only employees and participants of
MidAmerican Energy. This inclusion increased the benefit obligation by $14.8
million for the pension and nonqualified supplemental retirement plans and $2.8
million for the postretirement plans.

MidAmerican Energy also maintains noncontributory, nonqualified supplemental
executive retirement plans for active and retired participants.

During 2000, MidAmerican Energy adopted a market-related valuation of its
pension assets for purposes of calculating net periodic pension costs. This
change conforms MidAmerican Energy's accounting practices for pension costs to
that of the Company. Net periodic pension, supplemental retirement and
postretirement benefit costs included the following components for the Company:

PENSION COST
Service cost .................. $ 18,114 $ 13,014 $ 3,242 $ 9,854
Interest cost ................. 33,027 28,329 7,058 25,505
Expected return on plan assets (36,326) (38,532) (9,600) (37,392)
Amortization of net transition
obligation ................... (2,591) (2,074) (517) --
Amortization of prior service
cost ......................... 2,729 2,310 575 --
Amortization of prior year gain (3,894) (3,297) (822) --
Curtailment loss .............. -- -- -- 4,270
--------- --------- -------- ---------
Net periodic pension cost
(benefit) .................... $ 11,059 $ (250) $ (64) $ 2,237
========= ========= ======== =========

F-54

POSTRETIREMENT COST
Service cost ....................... $ 4,357 $ 2,089 $ 520 $ 2,478
Interest cost ...................... 10,418 6,688 1,666 6,423
Expected return on plan assets ..... (4,032) (3,947) (984) (3,540)
Amortization of net transition
obligation ........................ 4,110 3,290 820 --
Amortization of prior service
cost .............................. 425 340 85 --
Amortization of prior year
(gain) loss ....................... 332 (699) (174) --
-------- -------- ------ --------
Net periodic pension cost .......... $ 15,610 $ 7,761 $1,933 $ 5,361
======== ======== ====== ========

The pension plan assets are in external trusts and are comprised of corporate
equity securities, United States government debt, corporate bonds and insurance
contracts. The postretirement benefit plans assets are in external trusts and
are comprised primarily of corporate equity securities, corporate bonds, money
market investment accounts and municipal bonds.

Although the supplemental executive retirement plans had no plan assets as of
December 31, 2001, MidAmerican Energy has Rabbi trusts which hold
corporate-owned life insurance and other investments to provide funding for the
future cash requirements. Because these plans are nonqualified, the fair value
of these assets is not included in the following table. The fair value of the
Rabbi trust investments was $50.4 million and $44.7 million at December 31, 2001
and 2000, respectively.

During 1999 certain participants in the supplemental executive retirement plan
left MidAmerican Energy reducing the future service of active employees by 28%.
As a result, a curtailment loss of $5.3 million was recognized by the Company in
1999. Additionally, termination benefits provided to the participants, totaling
$3.5 million, were expensed by MidAmerican Energy during 1999.

The projected benefit obligation and accumulated benefit obligation for the
supplemental executive retirement plans were $91.2 million and $88.2 million,
respectively, as of December 31, 2001 and $82.7 million and $77.5 million,
respectively, as of December 31, 2000.

The following table presents a reconciliation of the beginning and ending
balances of the benefit obligation, fair value of plan assets and the funded
status of MidAmerican Energy's plans to the net amounts recognized in the
consolidated balance sheet as of December 31 (dollars in thousands):

F-55

2001 2001 2000 2000
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
------------ ---------------- ------------ ---------------

Reconciliation of benefit obligation:
Benefit obligation at beginning of year ............. $ 472,349 $ 131,822 $ 447,170 $ 107,744
Service cost ........................................ 18,114 4,357 16,256 2,609
Interest cost ....................................... 33,027 10,418 35,387 8,354
Participant contributions ........................... -- 3,059 74 2,395
Plan amendments ..................................... 652 -- (132) --
Actuarial (gain) loss ............................... 17,333 57,101 6,007 20,589
Benefits paid ....................................... (23,267) (11,840) (32,413) (9,869)
--------- ---------- ---------- ---------
Benefit obligation at end of year .................. 518,208 194,917 472,349 131,822
--------- ---------- ---------- ---------
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year ...... 555,208 75,090 605,059 72,622
Employer contributions .............................. 4,576 16,022 4,355 10,543
Participant contributions ........................... -- 3,059 74 2,395
Actual return on plan assets ........................ (20,627) (1,202) (21,867) (601)
Benefits paid ....................................... (23,267) (11,840) (32,413) (9,869)
--------- ---------- ---------- ---------
Fair value of plan assets at end of year ........... 515,890 81,129 555,208 75,090
--------- ---------- ---------- ---------
Funded status ....................................... (2,318) (113,788) 82,859 (56,732)
Unrecognized net (gain) loss ........................ (52,244) 63,328 (130,423) 1,326
Unrecognized prior service cost ..................... 22,885 4,264 24,962 4,689
Unrecognized net transition obligation (asset) ...... (5,974) 45,212 (8,566) 49,322
--------- ---------- ---------- ---------
Net amount recognized in the consolidated
balance sheet .................................... $ (37,651) $ (984) $ (31,168) $ (1,395)
========= ========== ========== =========
Amounts recognized in the consolidated balance
sheet consist of:
Prepaid benefit cost ................................ $ 15,381 $ 1,493 $ 16,773 $ 1,493
Accrued benefit liability ........................... (88,210) (2,477) (77,538) (2,888)
Intangible asset .................................... 22,796 -- 25,510 --
Accumulated other comprehensive income .............. 12,382 -- 4,087 --
--------- ---------- ---------- ---------
Net amount recognized .............................. $ (37,651) $ (984) $ (31,168) $ (1,395)
========= ========== ========== =========

PENSION AND POSTRETIREMENT
ASSUMPTIONS
---------------------------------------------
MEHC (PREDECESSOR)
-------------------
2001 2000 1999
---------- ---------- -------------------

Assumptions used were:
Discount rate .............................................. 6.50% 7.00% 7.75%
Rate of increase in compensation levels .................... 5.00% 5.00% 5.00%
Weighted average expected long-term rate of return on assets 7.00% 9.00% 9.00%

For purposes of calculating the postretirement benefit obligation, it is assumed
health care costs for all covered individuals will increase by 11.25% in 2002
and that the rate of increase thereafter will decrease to an ultimate rate of
5.25% by the year 2006.

If the assumed health care trend rates used to measure the expected cost of
benefits covered by the plans were increased by 1.0%, the total service and
interest cost for 2001 would increase by $3.0 million, and the postretirement
benefit obligation at December 31, 2001, would increase by $30.6 million. If the
assumed health care trend rates were to decrease by 1.0%, the total service and
interest cost for 2001 would decrease by $2.3 million and the postretirement
benefit obligation at December 31, 2001, would decrease by $24.2 million.

F-56

20. COMMITMENTS AND CONTINGENCIES

A. FINANCIAL CONDITION OF EDISON

Southern California Edison Company ("Edison"), a wholly-owned subsidiary of
Edison International, is a public utility primarily engaged in the business of
supplying electric energy to retail customers in Central and Southern
California, excluding Los Angeles. The Company is aware that there have been
public announcements that Edison's financial condition has deteriorated as a
result of reduced liquidity. Following Edison's recent financing, Edison's
senior unsecured debt obligations were upgraded to Ba3 by Moody's and BB by S&P.

Edison failed to pay approximately $119 million due under the power purchase
agreement with CE Generation affiliates for power delivered in November and
December 2000 and January, February and March 2001, although the Power Purchase
Agreements provide for billing and payment on a schedule where payments would
have normally been received in early January, February, March, April and May
2001.

On February 21, 2001, the Imperial Valley Projects (excluding the Salton Sea V
and Turbo Projects) filed a lawsuit against Edison in California's Imperial
County Superior Court seeking a court order requiring Edison to make the
required payments under the Power Purchase Agreements. The lawsuit also
requested, among other things, that the court order permit the Imperial Valley
Projects (excluding the Salton Sea V and Turbo Projects) to suspend deliveries
of power to Edison and to permit the Imperial Valley Projects to sell such power
to other purchasers in California.

On March 22, 2001, the Imperial County Superior Court granted the Imperial
Valley Projects' (excluding the Salton Sea V and Turbo Projects) Motion for
Summary Adjudication and a Declaratory Judgment ordering that: 1) under the
Power Purchase Agreements, the Imperial Valley Projects (excluding the Salton
Sea V and Turbo Projects) have the right to temporarily suspend deliveries of
capacity and energy to Edison, 2) such Imperial Valley Projects (excluding the
Salton Sea V and Turbo Projects) are entitled to resell the energy and capacity
to other purchasers and 3) the interim suspension of deliveries to Edison shall
not in any respect result in the modifications or termination of the Power
Purchase Agreements, and the Power Purchase Agreements shall in all respects
continue in full force and effect other than the temporary suspension of
deliveries to Edison.

As a result of the March 22, 2001 Declaratory Judgment, the Imperial Valley
Projects (excluding the Salton Sea V and Turbo Projects) suspended deliveries of
energy to Edison and entered into a transaction agreement with El Paso Merchant
Energy, L.P. ("EPME") in which the Imperial Valley Projects' (excluding the
Salton Sea V and Turbo Projects) available power was sold to EPME based on
percentages of the Dow Jones SP-15 Index. On June 18, 2001 the Superior Court
prospectively vacated its order authorizing the Imperial Valley Projects'
(excluding the Salton Sea V and Turbo Projects) right to resell power pursuant
to the Declaratory Judgment.

On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V and
CE Turbo) entered into Agreements Addressing Renewable Energy Pricing and
Payment Issues with Edison ("Settlement Agreements") and, as a result, resumed
power sales to Edison on June 22, 2001. The Settlement Agreements required that
Edison make an initial payment to repay the past due balances under the Power
Purchase Agreements (the "stipulated amounts"). The initial payment of
approximately $11.6 million, which represented 10% of the stipulated amounts,
was received June 22, 2001. On October 2, 2001, the California Public Utilities
Commission announced an agreement with Edison that allowed Edison to recover in
retail electric rates its past due obligations. On November 30, 2001, the
Settlement Agreements were amended to reflect when Edison would be required to
make the final payment on past due amounts. On March 1, 2002, Edison obtained
$1.8 billion in secured financing that, when combined with cash on hand, enabled
Edison to pay off its past due debts. The final payment of approximately $104.6
million, representing the remaining stipulated amounts, was received March 1,
2002. In addition to these payments, Edison was required to make monthly
interest payments calculated at a rate of 7% per annum on the outstanding
stipulated amounts. The amended Settlement Agreements provide a revised energy
pricing structure, whereby Edison elects to pay the Imperial Valley Projects a
fixed energy price in lieu

F-57

of the Commission-approved Avoided Cost of Energy Methodology under the Power
Purchase Agreements. The fixed energy price is 3.25 cents/kWh from December 2001
through April 30, 2002 and 5.37 cents/kWh commencing May 1, 2002 for a five year
period. Following the five year period, the energy payments revert back to the
Commission-approved Avoided Cost of Energy Methodology under the Power Purchase
Agreements. Estimates of Edison's future Avoided Cost of Energy vary
substantially from year to year.

As a result of Edison's failure to make the payments due under the Power
Purchase Agreements and the downgrades of Edison's credit rating, Moody's
downgraded the ratings for the Salton Sea Funding Corporation (the "Funding
Corporation") Securities to Caa2 (negative outlook) and S&P downgraded the
ratings for the Funding Corporation Securities to BBB- and placed the Securities
on "credit watch negative." Moody's downgraded the ratings for the CE Generation
Securities to B1 from Baa3 (review for possible downgrade). Following the
execution of the Settlement Agreements, Moody's placed the Salton Sea Funding
and CE Generation securities on "credit watch positive." The Funding Corporation
Securities are currently rated Ba3 by Moody's and BBB- by S&P. CE Generation
Securities are currently Ba2 by Moody's and BBB- by S&P.

B. CASECNAN

The Casecnan Project was initially being constructed pursuant to a fixed-price,
date-certain, turnkey construction contract (the "Hanbo Contract") on a joint
and several basis by Hanbo Corporation ("Hanbo") and Hanbo Engineering and
Construction Co., Ltd. ("HECC"), both of which are South Korean corporations. As
of May 7, 1997, the Company terminated the Hanbo Contract due to defaults by
Hanbo and HECC including the insolvency of both companies. On the same date, the
Company entered into a new fixed-price, date certain, turnkey engineering,
procurement and construction contract to complete the construction of the
Casecnan Project (the "Replacement Contract"). The work under the Replacement
Contract is being conducted by a consortium consisting of Cooperativa Muratori
Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., working together
with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power
Engineering Ltd. (collectively, the "Contractor").

On November 20, 1999, the Replacement Contract was amended to extend the
Guaranteed Substantial Completion Date for the Casecnan Project to March 31,
2001. This amendment was approved by the lender's independent engineer under the
Casecnan Indenture.

On February 12, 2001, the Contractor filed a Request for Arbitration with the
International Chamber of Commerce seeking an extension of the Guaranteed
Substantial Completion Date by up to 153 days through August 31, 2001 resulting
from various alleged force majeure events. In a March 20, 2001 Supplement to
Request for Arbitration, the Contractor also seeks compensation for alleged
additional costs of approximately $4 million it incurred from the claimed force
majeure events to the extent it is unable to recover from its insurer. On April
20, 2001, the Contractor filed a further supplement seeking an additional
approximately $62 million in damages for the alleged force majeure event (and
geologic conditions) related to the collapse of the surge shaft. The Contractor
alleged that the circumstances surrounding the placing of the Casecnan Project
into commercial operation on December 11, 2001 amounted to a termination of the
Replacement Contract and filed a claim for unspecified quantum meruit damages.
CE Casecnan believes such allegations and claims are without merit and is
vigorously defending the Contractor's claims. The arbitration is being conducted
applying New York law and pursuant to the rules of the International Chamber of
Commerce.

On June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from
making calls on the demand guaranty posted by Banca di Roma in support of the
Contractor's obligations to CE Casecnan for delay liquidated damages. Hearings
on the force majeure claims were held in London from July 2 to 14, 2001, and
hearings on the Contractor's April 20, 2001 supplement were held in London from
September 24 to October 3, 2001. Further hearings were held from January 2 to
February 1, 2002 and additional hearings were held from March 14 to 19, 2002.

As of December 31, 2001 the Company has received approximately $6.0 million of
liquidated damages from demands made or the demand guarantees posted by
Commerzbank on behalf of the Contractor.

F-58

Although the outcome of the arbitration is difficult to assess, CE Casecnan
believes it will prevail and receive substantial additional liquidated damages
in the arbitration.

Under the Project Agreement, if NIA is able to accept delivery of water into the
Pantabangan Reservoir and NPC has completed the Project's related transmission
line, the Company is liable to pay NIA $5,500 per day for each day of delay in
completion of the Casecnan Project beyond July 27, 2000, increasing to $13,500
per day for each day of delay in completion beyond November 27, 2000. NIA
completed the installation of the transmission line on August 13, 2001.
Accordingly, the Company accrued $1.6 million liquidated damages payable to NIA
for 120 days of delay.

The Company's ability to make payments on any of its existing and future
obligations is dependent on NIA's and the Republic of the Philippines'
performance of their obligations under the Project Agreement and the Performance
Undertaking, respectively. Except to the extent expressly provided for in the
Shareholder Support Letters, no shareholders, partners or affiliates of the
Company, including MidAmerican, and no directors, officers or employees of the
Company will guarantee or be in any way liable for payment of the Company's
obligations. As a result, payment of the Company's obligations depends upon the
availability of sufficient revenues from the Company's business after the
payment of operating expenses.

C. DECOMMISSIONING COSTS

Expected decommissioning costs for Quad Cities Station and Cooper have been
developed based on site-specific decommissioning studies that include
decontamination, dismantling, site restoration, dry fuel storage cost and
assumed shutdown dates. In Illinois, Cooper nuclear decommissioning costs are
recovered through a rate rider on customer billings that permits annual
adjustments. Quad Cities Station and Cooper decommissioning costs are reflected
as base rates in Iowa tariffs.

MidAmerican Energy's share of expected decommissioning costs for Quad Cities
Station, in 2001 dollars, is $278 million. MidAmerican Energy has established
external trusts for the investment of funds for decommissioning the Quad Cities
Station. The total accrued balance as of December 31, 2001, was $158.3 million
and is included in other long-term accrued liabilities, and a like amount is
reflected in Investments and represents the fair value of the assets held in the
trusts.

MidAmerican Energy's depreciation expense included costs for Quad Cities Station
nuclear decommissioning of $8.3 million, $8.3 million, and $10.4 million for
2001, 2000 and 1999, respectively. The provision charged to depreciation expense
is equal to the funding that is being collected in rates. The decommissioning
funding component of MidAmerican Energy's Illinois and Iowa tariffs assumes
decommissioning costs, related to the Quad Cities Station, will escalate at an
annual rate of 4.5% and the assumed annual return on funds in the trust is 6.9%.
Realized income (loss), net of investment fees, on the assets in the trust fund
was $(0.6) million, $1.9 million and $1.9 million for 2001, 2000 and 1999,
respectively.

MidAmerican Energy's contribution toward payment of Cooper's projected
decommissioning costs have been based on the NPPD decommissioning funding plan
for Cooper. Total expected decommissioning costs for Cooper, in 2001 dollars,
are $577 million. For purposes of developing a decommissioning funding plan for
Cooper, the NPPD assumes that decommissioning costs will escalate at an annual
rate of 4.0%. Although Cooper's operating license expires in 2014, the funding
plan assumes decommissioning will start in 2004, the anticipated plant shutdown
date.

As of December 31, 2001, total funds set aside in the internal and external
accounts for Cooper decommissioning that are maintained by the NPPD were $291.3
million. In addition, the funding plan for Cooper also assumes various funds and
reserves currently held to satisfy the NPPD bond resolution requirements will be
available for plant decommissioning, which is to begin with the assumed plant
shutdown in September 2004. The funding schedule assumes a long-term return on
funds in the trust of 6.75% annually. Certain funds will be required to be
invested on a short-term basis when decommissioning begins and are assumed to
earn at a rate of 4.0% annually. Earnings from the internal account and external
trust fund, which are recognized by the NPPD as the owner of the plant, are tax
exempt and serve to reduce future funding requirements.

F-59

Beginning in December 2000, MidAmerican Energy ceased contributing to the
accounts maintained by NPPD and began contributing funds to a separate
MidAmerican Energy bank account based on the NPPD decommissioning funding plan
for Cooper. A liability equal to the amount of funds contributed, plus the
earnings on those funds, is reflected in other long-term accrued liabilities on
the consolidated balance sheets. MidAmerican Energy records expense equal to the
funds contributed to the separate account plus investment fees paid to the NPPD
for funds in the accounts they maintain. MidAmerican Energy's expense for Cooper
decommissioning was $11.6 million, $11.5 million and $11.3 million for the years
2001, 2000 and 1999, respectively, and is included in other operating expenses.

MidAmerican Energy is currently involved in litigation with NPPD in part related
to the determination of MidAmerican Energy's obligation, if any, for costs of
decommissioning Cooper. Refer to Note (20)(E) for a discussion of the
proceedings.

D. NUCLEAR INSURANCE

MidAmerican Energy maintains financial protection against catastrophic loss
associated with its interest in Quad Cities Station and Cooper through a
combination of insurance purchased by NPPD (the owner and operator of Cooper)
and Exelon Generation Company, LLC (the operator and joint owner of Quad Cities
Station), insurance purchased directly by MidAmerican Energy, and the mandatory
industry-wide loss funding mechanism afforded under the Price-Anderson
Amendments Act of 1988. The general types of coverage are: nuclear liability,
property coverage and nuclear worker liability.

NPPD and Exelon Generation each purchase nuclear liability insurance for Cooper
and Quad Cities Station, respectively, in the maximum available amount of $200
million. In accordance with the Price-Anderson Amendments Act of 1988, excess
liability protection above the amount is provided by a mandatory industry-wide
program under which the licensees of nuclear generating facilities could be
assessed for liability incurred due to a serious nuclear incident at any
commercial nuclear reactor in the United States. Currently, MidAmerican Energy's
aggregate maximum potential share of an assessment for Cooper and Quad Cities
Station combined is $88.1 million per incident, payable in installments not to
exceed $10 million annually.

The property coverage provides for property damage, stabilization and
decontamination of the facility, disposal of the decontaminated material and
premature decommissioning. For Quad Cities Station, Exelon Generation purchases
primary and excess property insurance protection for the combined interests in
Quad Cities Station, with coverage limits totaling $2.1 billion. For Cooper,
MidAmerican Energy and NPPD separately purchase primary and excess property
insurance protection for their respective obligations, with coverage limits of
$1.375 billion each. This structure provides that both MidAmerican Energy and
NPPD are covered for their respective 50% obligation in the event of a loss
totaling up to $2.75 billion. MidAmerican Energy also directly purchases extra
expense/business interruption coverage for its share of replacement power and/or
other extra expenses in the event of a covered accidental outage at Cooper or
Quad Cities Station. The coverages purchased directly by MidAmerican Energy, and
the property coverages purchased by Exelon Generation, which includes the
interests of MidAmerican Energy, are underwritten by an industry mutual
insurance company and contain provisions for retrospective premium assessments
should two or more full policy-limit losses occur in one policy year. Currently,
the maximum retrospective amounts that could be assessed against MidAmerican
Energy from industry mutual policies for its obligations associated with Cooper
and Quad Cities Station combined, total $20.5 million.

The master nuclear worker liability coverage, which is purchased by NPPD and
Exelon Generation for Cooper and Quad Cities Station, respectively, is an
industry-wide guaranteed-cost policy with an aggregate limit of $200 million for
the nuclear industry as a whole, which is in effect to cover tort claims in
nuclear-related industries.

E. COOPER LITIGATION

On July 23, 1997, the Nebraska Public Power District ("NPPD") filed a complaint,
in the United States District Court for the District of Nebraska, naming
MidAmerican Energy as the defendant and seeking

F-60

declaratory judgment as to three issues under the parties' long-term power
purchase agreement for Cooper capacity and energy. More specifically, the NPPD
sought a declaratory judgment in the following respects:

(1) that MidAmerican Energy is obligated to pay 50% of all costs and expenses
associated with decommissioning Cooper, and that in the event NPPD
continues to operate Cooper after expiration of the power purchase
agreement (September 2004), MidAmerican Energy is not entitled to
reimbursement of any decommissioning funds it has paid to date or will pay
in the future;

(2) that the current method of allocating transition costs as a part of the
decommissioning cost is proper under the power purchase agreement; and

(3) that the current method of investing decommissioning funds is proper under
the power purchase agreement.

MidAmerican Energy filed its answer and counterclaims. The counterclaims filed
by MidAmerican Energy are generally as follows:

(1) that MidAmerican Energy has no duty under the power purchase agreement to
reimburse or pay 50% of the decommissioning costs unless conditions to
reimbursement occur;

(2) that the term "monthly power costs" as defined in the power purchase
agreement does not include costs and expenses associated with
decommissioning the plant;

(3) that NPPD violated MidAmerican Energy's directions for application of
payments;

(4) that transition costs are not included in any decommissioning costs and are
not any kind of costs that MidAmerican Energy is obligated to pay;

(5) that NPPD has the duty to repay all amounts that MidAmerican Energy has
prefunded for decommissioning in the event the Nebraska Public Power
District operates the plant after the term of the power purchase agreement;

(6) that NPPD is equitably estopped from continuing to operate the plant after
the term of the power purchase agreement so long as NPPD does not repay all
amounts MidAmerican Energy has prefunded for estimated decommissioning
costs together with other amounts in certain funds and accounts and for so
long as NPPD fails to provide MidAmerican Energy with certain requested
accountings and information;

(7) that certain funds, accounts, and reserves are excessive and are required
to be paid to MidAmerican Energy or credited to MidAmerican Energy's
pre-2004 monthly power costs;

(8) that MidAmerican Energy has no duty to pay for nuclear fuel, operations and
maintenance projects or capital improvements that have useful lives after
the term of the power purchase agreement;

(9) that NPPD has mismanaged the plant in numerous described transactions
resulting in damage to MidAmerican Energy;

(10) that NPPD has breached its contractual and other duties to MidAmerican
Energy by not joining certain litigation and by failing to credit or agree
to credit MidAmerican Energy with any recovery for low-level radioactive
waste; and

(11) that NPPD has breached its duty to MidAmerican Energy in making investments
of decommissioning funds;

On October 6, 1999, the court rendered summary judgment for NPPD on the
above-mentioned issue concerning liability for decommissioning (issue one
in the first paragraph above) and the related contingent counterclaims
filed by MidAmerican Energy (issues one and two in the second paragraph
above). The court referred all remaining issues in the case to mediation,
and cancelled the November 1999 trial date.

F-61

MidAmerican Energy appealed the court's summary judgment ruling. On December
12, 2000, the United States Court of Appeals for the Eighth Circuit reversed
the ruling of the district court and granted summary judgment in favor of
MidAmerican Energy on issues one and five in the second paragraph above.
Additionally, it remanded the case for trial on all other claims and
counterclaims.

Since the remand to the District Court from the Eighth Circuit Court of Appeals,
NPPD has been granted permission, over MidAmerican Energy's objections, to file
a second amended complaint. The second amended complaint asserts that even
though the Eighth Circuit Court of Appeals held that MidAmerican Energy has no
liability under the power purchase agreement to reimburse or pay NPPD a 50%
share of decommissioning costs unless certain conditions occur, MidAmerican
Energy has unconditional liability for a 50% share based on agreements other
than the power purchase agreement as originally written. NPPD's post-remand
contentions - all strongly disputed by MEC - are that MidAmerican Energy has
unconditional liability for a 50% share of decommissioning based on any of the
following alternative theories: (i) the parties without written amendment either
modified the power purchase agreement or made a separate agreement that imposes
unconditional liability on MidAmerican Energy for decommissioning costs; (ii)
absent unconditional liability for a 50% share of decommissioning costs,
MidAmerican Energy would be unjustly enriched; (iii) MidAmerican Energy has
unconditional liability for a 50% share of decommissioning costs based on
promissory estoppel; or (iv) NPPD is entitled to have the power purchase
agreement reformed to provide that MidAmerican Energy has unconditional
liability for a 50% share of decommissioning costs. In response to NPPD's second
amended complaint, MidAmerican Energy filed its first amended answer and third
amended counterclaims containing denials, several affirmative defenses, and the
counterclaims summarized above. In the course of discovery, NPPD has contended
that MidAmerican Energy has some responsibility for some costs of storage of
spent fuel resulting from the operation of the plant during the term of the
power purchase agreement. MidAmerican Energy disputes this. MidAmerican Energy
recently filed a mandamus petition with Eighth Circuit Court of Appeals seeking
an order of that court directing the District Court not to permit NPPD to pursue
the above alternative theories at trial, since the above alternative theories
appear to be contrary to the December 12, 2000 Eighth Circuit Court of Appeals
decision. If such relief is not granted, MidAmerican Energy will strongly
dispute at trial these contentions and theories put forth by NPPD. Trial in
these matters has been recently rescheduled to being on September 9, 2002.

F. COAL AND NATURAL GAS CONTRACT COMMITMENTS

MidAmerican Energy has supply and related transportation contracts for its
fossil fueled generating stations. The contracts, with expiration dates ranging
from 2002 to 2007, require minimum payments of $80.3 million, $70.6 million,
$36.2 million, $34.0 million and $2.6 million for the years 2002 through 2006,
respectively, and $2.6 million for the total of the years thereafter.
MidAmerican Energy expects to supplement these coal contracts with additional
contracts and spot market purchases to fulfill its future fossil fuel needs.

MidAmerican Energy has contracts with various companies to purchase electric
capacity. The contracts, with expiration dates ranging from 2002 to 2011,
require minimum payments of $27.0 million, $30.5 million, $15.3 million, $2.9
million and $2.2 million for the years 2002 through 2006, respectively, and
$11.0 million for the total of the years thereafter.

MidAmerican Energy has various natural gas supply and transportation contracts
for its gas operations. The minimum commitments under these contracts are $56.6
million, $41.3 million, $13.4 million, $13.2 million and $13.0 million for the
years 2002 through 2006, respectively, and $26.7 million for the total of the
years thereafter.

21. SUBSEQUENT EVENTS

Debt issuance

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

F-62

Prudential California Acquisition

In February 2002, HomeServices completed its purchase of a majority interest in
Prudential California Realty. The cash purchase price of Prudential California
Realty was approximately $74 million, with an option to purchase the remaining
interests. Additionally, HomeServices is obligated to pay a maximum earnout of
$18.5 million calculated based on certain 2002 financial performance measures.
The purchase price was financed using the Company's corporate revolver for $40
million which was contributed to HomeServices as equity and the remaining funds
were borrowed from available credit under the HomeServices's $65 million
revolving credit facility. It is anticipated that the borrowings in connection
with this acquisition will be repaid from HomeServices generated funds. The
acquisition will be accounted for by the purchase method of accounting, and the
Company is in the process of completing the allocation of the purchase price to
the assets acquired and liabilities assumed.

Kern River Acquisition

On March 7, 2002, the Company reached a definitive agreement with The Williams
Companies, Inc. ("Williams") to acquire Williams' Kern River Gas Transmission
Company, a 926-mile interstate pipeline transporting Rocky Mountain and Canadian
natural gas to markets in California, Nevada and Utah. The purchase price was
$956 million, including $506 million of assumed debt. As part of the agreement,
the Company will continue the planned expansion of the Kern River system, a
project that will more than double the pipeline's capacity with expected capital
expenditures of approximately $1.2 billion. The purchase was completed on March
27, 2002.

The Kern River pipeline is an important route for the transmission of natural
gas from the vast reserves in the Rocky Mountain states to the rapidly growing
markets in Utah, Nevada and California. Constructed in 1992, Kern River extends
926 miles from Opal, Wyoming, to the San Joaquin Valley near Bakersfield,
California, and has a design capacity of 835 million cubic feet per day.

In August 2001, Williams filed with FERC to more than double the capacity on the
Kern River system by adding approximately 900 million cubic feet per day of
additional capacity from Wyoming to California and markets in between. Upon
completion of the expansion project in May 2003, Kern River will be capable of
transporting 1.7 billion cubic feet of natural gas per day. When converted to
electricity, that is enough energy to power approximately 10 million homes.

In connection with the acquisition of Kern River, the Company issued $323
million of Trust Preferred Securities and $127 million of convertible preferred
stock to Berkshire Hathaway.

In addition to the acquisition of Kern River, the Company also announced its
investment of $275 million in Williams, in exchange for shares of 9 7/8 percent
cumulative convertible preferred stock of Williams. In connection with this
investment, the Company issued $275 million of convertible preferred stock to
Berkshire Hathaway.

22. SEGMENT INFORMATION:

The Company has identified five reportable operating segments principally based
on management structure: CalEnergy Generation -- Domestic, CalEnergy Generation
- -- Foreign (primarily the Philippines), MidAmerican Energy (domestic utility
operations), CE Electric UK Funding (foreign utility operations) and
HomeServices (real estate operations). Information related to the Company's
reportable operating segments are shown below (in thousands).

F-63

REVENUE: (1)
CalEnergy Generation -- Domestic .... $ 75,541 $ 40,031 $ 4,520 $ 105,869
CalEnergy Generation -- Foreign ..... 207,386 156,504 42,726 210,571
MidAmerican Energy .................. 2,795,838 2,132,273 491,636 1,525,157
CE Electric UK Funding .............. 1,458,979 1,517,539 499,017 2,098,976
HomeServices ........................ 644,741 405,805 66,880 357,728
---------- ---------- ---------- ----------
Segment revenue ..................... 5,182,485 4,252,152 1,104,779 4,298,301
Corporate/other ..................... (25,174) (9,403) 1,830 29,420
---------- ---------- ---------- ----------
$5,157,311 $4,242,749 $1,106,609 $4,327,721
========== ========== ========== ==========
DEPRECIATION AND AMORTIZATION:
CalEnergy Generation -- Domestic .... $ 5,439 $ 2,183 $ 250 $ 14,478
CalEnergy Generation -- Foreign ..... 66,315 52,685 13,514 66,063
MidAmerican Energy .................. 286,590 184,955 45,184 182,638
CE Electric UK Funding .............. 125,564 108,637 31,964 137,963
HomeServices ........................ 17,201 8,695 2,891 7,772
---------- ---------- ---------- ----------
Segment depreciation ................ 501,109 357,155 93,803 408,914
Corporate/other ..................... 37,593 26,196 3,475 18,776
---------- ---------- ---------- ----------
$ 538,702 $ 383,351 $ 97,278 $ 427,690
========== ========== ========== ==========
INTEREST EXPENSE, NET:
CalEnergy Generation -- Domestic .... $ 10,835 $ 1,829 $ 793 $ 17,851
CalEnergy Generation -- Foreign ..... 30,875 34,458 9,713 58,322
MidAmerican Energy .................. 113,980 94,425 24,579 100,046
CE Electric UK Funding .............. 112,308 74,335 21,189 96,759
HomeServices ........................ 3,884 2,328 785 3,228
---------- ---------- ---------- ----------
Segment interest expense, net ....... 271,882 207,375 57,059 276,206
Corporate/other ..................... 140,912 104,029 28,755 149,967
---------- ---------- ---------- ----------
$ 412,794 $ 311,404 $ 85,814 $ 426,173
========== ========== ========== ==========
INCOME BEFORE PROVISIONS FOR INCOME TAXES: (1)
CalEnergy Generation -- Domestic .... $ 44,335 $ 30,697 $ 2,877 $ 49,095
CalEnergy Generation -- Foreign ..... 89,542 49,787 15,976 68,105
MidAmerican Energy .................. 210,733 181,797 63,315 151,555
CE Electric UK Funding .............. 159,850 83,108 58,673 152,126
HomeServices ........................ 42,945 31,015 (4,929) 16,613
---------- ---------- ---------- ----------
Segment income ...................... 547,405 376,404 135,912 437,494
Corporate/other ..................... (223,014) (157,200) (37,137) (164,720)
---------- ---------- ---------- ----------
$ 324,391 $ 219,204 $ 98,775 $ 272,774
========== ========== ========== ==========

F-64

PROVISIONS FOR INCOME TAXES: (1)
CalEnergy Generation -- Domestic .... $ (689) $ (1,929) $ (8) $ 6,347
CalEnergy Generation -- Foreign ..... 27,962 29,194 373 33,912
MidAmerican Energy .................. 95,490 77,450 27,943 64,936
CE Electric UK Funding .............. 47,866 30,065 18,761 59,183
HomeServices ........................ 15,953 12,300 (1,992) 7,193
---------- --------- --------- ---------
Segment income ...................... 186,582 147,080 45,077 171,571
Corporate/other ..................... (100,314) (93,803) (14,069) (80,835)
---------- --------- --------- ---------
$ 86,268 $ 53,277 $ 31,008 $ 90,736
========== ========= ========= =========
CAPITAL EXPENDITURES:
CalEnergy Generation -- Domestic .... $ 52,940 $ 151,289 $ 53,011 $ 145,255
CalEnergy Generation -- Foreign ..... 83,954 87,781 22,263 95,552
MidAmerican Energy .................. 252,615 194,045 23,977 194,216
CE Electric UK Funding .............. 176,464 95,806 22,210 231,634
HomeServices ........................ 9,878 6,996 2,052 9,143
---------- --------- --------- ---------
Segment capital expenditures ........ 575,851 535,917 123,513 675,800
Corporate/other ..................... 901 2,812 28 120
---------- --------- --------- ---------
$ 576,752 $ 538,729 $ 123,541 $ 675,920
========== ========= ========= =========

- ----------

(1) Before non-recurring items

AS OF DECEMBER 31, MEHC (PREDECESSOR)
------------------------------ AS OF DECEMBER 31,
2001 2000 1999
------------- -------------- -------------------

TOTAL ASSETS:
CalEnergy Generation -- Domestic ......... $ 725,716 $ 663,125 $ 538,598
CalEnergy Generation -- Foreign .......... 925,825 965,913 1,115,661
MidAmerican Energy ....................... 5,023,584 5,324,921 5,072,788
CE Electric UK Funding ................... 3,973,457 2,414,394 2,953,288
HomeServices ............................. 226,588 169,470 166,658
----------- ----------- -----------
Segment assets ........................... 10,875,170 9,537,823 $ 9,846,993
===========
Corporate/other .......................... 1,740,163 2,073,116
----------- -----------
$12,615,333 $11,610,939
=========== ===========
LONG-LIVED ASSETS:
CalEnergy Generation -- Domestic ......... $ 441,603 $ 434,523 $ 222,357
CalEnergy Generation -- Foreign .......... 802,092 790,077 809,506
MidAmerican .............................. 4,050,285 4,079,250 3,995,763
CE Electric UK Funding ................... 3,302,560 1,884,951 2,438,877
HomeServices ............................. 165,689 125,894 129,649
----------- ----------- -----------
Segment long-lived assets ................ 8,762,229 7,314,695 $ 7,596,152
===========
Corporate ................................ 1,404,307 1,707,102
----------- -----------
$10,166,536 $ 9,021,797
=========== ===========

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

F-65

23. EXCESS OF COST OVER FAIR VALUE OF NET ASSETS ACQUIRED:

On January 1, 2002, the Company adopted Statement of Financial Accounting
Standards ("SFAS ") No. 142, "Goodwill and Other Intangible Assets," which
establishes the accounting for acquired goodwill and other intangible assets.
SFAS No. 142 requires that amortization of goodwill and indefinite-lived
intangible assets be discontinued and that entities disclose net income for
prior periods adjusted to exclude such amortization and related income tax
effects, as well as a reconciliation from the originally reported net income to
the adjusted net income. The Company's related amortization consists of goodwill
amortization and the related income tax effect. Following is a reconciliation of
net income as originally reported for the year ended December 31, 2001, the
period March 14, 2000 through December 31, 2000, the period January 1, 2000
through March 13, 2000, and the year ended December 31, 1999,to adjusted net
income (in thousands):

MEHC (PREDECESSOR)
---------------------------
MARCH 14, JANUARY 1,
2000 2000
YEAR ENDED THROUGH THROUGH YEAR ENDED
DECEMBER 31, DECEMBER 31, MARCH 13, DECEMBER 31,
2001 2000 2000 1999
-------------- -------------- ----------- -------------

Net income as originally reported ......... $142,669 $ 81,257 $51,312 $167,230
Goodwill amortization ..................... 96,418 79,997 14,181 63,953
Income tax benefit ........................ (2,018) (1,433) (352) (1,685)
-------- -------- ------- --------
Net income as adjusted .................... $237,069 $159,821 $65,141 $229,498
======== ======== ======= ========

F-66

DEALER PROSPECTUS DELIVERY OBLIGATION

Until , 200 , all dealers that effect transactions in these securities,
whether or not participating in the offering, may be required to deliver a
prospectus. This is in addition to the dealer's obligation to deliver a
prospectus when acting as underwriters and with respect to their unsold
allotments or subscriptions.

[MIDAMERICAN ENERGY HOLDINGS COMPANY LOGO]

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

EXCHANGE AGENT:

THE BANK OF NEW YORK

By Facsimile:
(212) 298-1915

Confirm by telephone:
(212) 815-5920

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

PART II
INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

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

Sections 490.850 through 490.858 of the Iowa Business Corporation Act (the
"IBCA") permit corporations organized thereunder to indemnify directors,
officers, employees and agents against liability under certain circumstances.
Section 490.851 of the IBCA provides that a corporation may indemnify its
officers and directors if (i) the person acted in good faith, and (ii) the
person reasonably believed, in the case of conduct in the person's official
capacity with the corporation, that the conduct was in the corporation's best
interests, and in all other cases, that the person's conduct was at least not
opposed to the corporation's best interests, and (iii) in the case of any
criminal proceeding, the person had no reasonable cause to believe the person's
conduct was unlawful.

The Registrant's Amended and Restated Articles of Incorporation and Bylaws
provide that the Registrant shall indemnify, to the fullest extent permitted by
the IBCA, its directors, officers, employees and agents, (2) any person serving
as the legal representative of a director, officer, employee or agent, and (3)
any person who is or was serving at the request of the Registrant as director,
officer or employee of another corporation, joint venture, partnership, trust or
other venture. Such indemnification is provided by the Registrant to such
persons for all reasonable expenses, liability and loss incurred in connection
with any civil, criminal, administrative or investigative proceeding, formal or
informal, to which the person is, or is threatened to be made a party, whether
the basis of such proceeding is alleged action in an official capacity or any
other capacity while serving as director, officer, or employee.

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

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

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

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

II-1

ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a) Exhibits

EXHIBIT NO. DESCRIPTION
- ------------- --------------------------------------------------------------------------------------------

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

4.1 Indenture, dated as of October 4, 2002, by and between the Company and The Bank of New York,
relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012.

4.2 First Supplemental Indenture, dated as of October 4, 2002, by and between the Company and
The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior
Notes due 2012.

4.3 Registration Rights Agreement, dated as of October 1, 2002, by and between the Company and
Credit Suisse First Boston (as Representative for the Initial Purchasers).

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

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

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

4.7 Form of Second Supplemental Indenture for the 6.96% Senior Notes in the principal
amount of $215,000,000 due 2003, 7.23% Senior Notes in the principal amount of
$260,000,000 due 2005, 7.52% Senior Notes in the principal amount of $450,000,000 due
2008, and 8.48% Senior Notes in the principal amount of $475,000,000 due 2028, dated as of
September 22, 1998 between the Company and IBJ Schroder Bank & Trust Company, as
Trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on
Form 8-K dated September 17, 1998.)

4.8 Form of Third Supplemental Indenture for the 7.52% Senior Notes in the principal amount
of $100,000,000 due 2008, dated as of November 13, 1998, between the Company and IBJ
Schroder Bank & Trust Company, as Trustee (incorporated by reference to the Company's
Current Report on Form 8-K dated November 10, 1998).

4.9 Indenture, dated as of March 14, 2000, among the Company and the Bank of New York, as
Trustee (incorporated by reference to Exhibit 4.9 to the Company's Annual Report on
Form 10-K/A for the year ended December 31, 1999).

4.10 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 14, 2000
(incorporated by reference to Exhibit 4.10 to the Company's Annual Report on Form
10-K/A for the year ended December 31, 1999).

II-2

EXHIBIT NO. DESCRIPTION
- ------------- -----------------------------------------------------------------------------------------

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

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

4.14 Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of
August 16, 2002.

4.15 Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of
March 12, 2002.

4.16 Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of
March 14, 2000.

4.17 Indenture, dated as of August 16, 2002 between the Company and the Bank of New York,
as Trustee.

4.18 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of August 16, 2002.

4.19 Shareholders Agreement dated as of March 14, 2000.

5.1 Opinion of Willkie Farr & Gallagher.*

8.1 Opinion of Willkie Farr & Gallagher with respect to certain tax matters.*

10.1 Employment Agreement between the Company and David L. Sokol, dated May 10, 1999
(incorporated by reference to Exhibit 10.1 to the Company's Annual Report on Form
10-K/A for the year ended December 31, 1999).

10.2 Amendment No. 1 to the Amended and Restated Employment Agreement between the
Company and David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit
10.2 to the Company's Annual Report on Form 10-K/A for the year ended December 31,
1999).

10.3 Non-Qualified Stock Options Agreements of David L. Sokol dated March 14, 2000.

10.4 Amended and Restated Employment Agreement between the Company and Gregory E.
Abel, dated May 10, 1999 (incorporated by reference to Exhibit 10.3 to the Company's
Annual Report on Form 10-K/A for the year ended December 31, 1999).

10.5 Non-Qualified Stock Options Agreements of Gregory E. Abel dated March 14, 2000.

10.6 Employment Agreement between the Company and Patrick J. Goodman, dated April 21,
1999 (incorporated by reference to Exhibit 10.5 to the Company's Annual Report on Form
10-K/A for the year ended December 31, 1999).

10.7 MidAmerican Energy Holdings Company Long Term Incentive Partnership Plan.

II-3

EXHIBIT NO. DESCRIPTION
- ------------- ---------------------------------------------------------------------------------------------

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

10.10 Credit Agreement dated as of April 8, 1994 between CE Cebu Geothermal Power
Company, Inc., Export-Import Bank of the United States (incorporated by reference to
Exhibit 10.97 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).

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

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

10.13 180 MW Power Plant--Mahanagdong Agreement dated September 18, 1993 between
PNOC-Energy Development Corporation and CE Philippines Ltd. and the Company, as
amended by the First Amendment to Mahanagdong Agreement dated June 22, 1994, the
Letter Agreement dated July 12, 1994, the Letter Agreement dated July 29, 1994, and the
Fourth Amendment to Mahanagdong Agreement dated March 3, 1995 (incorporated by
reference to Exhibit 10.100 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1993).

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

10.15 Credit Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power
Company, Inc. and Export-Import Bank of the United States (incorporated by reference to
Exhibit 10.102 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).

10.16 Finance Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power
Company, Inc. and Overseas Private Investment Corporation (incorporated by reference to
Exhibit 10.103 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).

II-4

EXHIBIT NO. DESCRIPTION
- ------------- -----------------------------------------------------------------------------------------

10.18 Overseas Private Investment Corporation Contract of Insurance dated July 29, 1994
between Overseas Private Investment Corporation and the Company, CE International
Ltd., CE Mahanagdong Ltd. and American Pacific Finance Company and Amendment No.
1 dated August 3, 1994 (incorporated by reference to Exhibit 10.105 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1993).

10.19 231 MW Power Plant--Malitbog Agreement dated September 10, 1993 between PNOC-
Energy Development Corporation and Magma Power Company and the First and Second
Amendments thereto dated December 8, 1993 and March 10, 1994, respectively (incorporated
by reference to Exhibit 10.106 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1993).

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

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

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

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

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

10.25 Trust Indenture dated as of November 27, 1995 between the CE Casecnan Water and
Energy Company, Inc. and Chemical Trust Company of California (incorporated by
reference to Exhibit 4.1 to CE Casecnan Water and Energy Company, Inc.'s Registration
Statement on Form S-4 dated January 25, 1996).

10.26 Amended and Restated Casecnan Project Agreement between the National Irrigation
Administration and CE Casecnan Water and Energy Company Inc. dated June 26, 1995
(incorporated by reference to Exhibit 10.1 to CE Casecnan Water and Energy Company,
Inc.'s Registration Statement on Form S-4 dated January 25, 1996).

II-5

EXHIBIT NO. DESCRIPTION
- ------------- --------------------------------------------------------------------------------------------

10.28 Indenture and First Supplemental Indenture, dated March 11, 1999, between MidAmerican
Funding LLC and IBJ Whitehall Bank & Trust Company and the First Supplement thereto
relating to the $700 million Senior Notes and Bonds (incorporated by reference to the
Company's Annual Report on Form 10-K for the year ended December 31, 1998).

10.29 General Mortgage Indenture and Deed of Trust dated as of January 1, 1993, between
Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee
(incorporated by reference to Exhibit 4(b)-1 to the Midwest Resources Inc. Annual Report
on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).

10.30 First Supplemental Indenture dated as of January 1, 1993, between Midwest Power Systems
Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by
reference to Exhibit 4(b)-2 to the Midwest Resources Inc. Annual Report on Form 10-K for
the year ended December 31, 1992, Commission File No. 1-10654).

10.31 Second Supplemental Indenture dated as of January 15, 1993, between Midwest Power
Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by
reference to Exhibit 4(b)-3 to the Midwest Resources Inc. Annual Report on Form 10-K for
the year ended December 31, 1992, Commission File No. 1-10654).

10.32 Third Supplemental Indenture dated as of May 1, 1993, between Midwest Power Systems
Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by
reference to Exhibit 4.4 to the Midwest Resources Inc. Annual Report on Form 10-K for the
year ended December 31, 1993, Commission File No. 1-10654).

10.33 Fourth Supplemental Indenture dated as of October 1, 1994, between Midwest Power
Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to
Exhibit 4.5 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended
December 31, 1994, Commission File No. 1-10654).

10.34 Fifth Supplemental Indenture dated as of November 1, 1994, between Midwest Power
Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to
Exhibit 4.6 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended
December 31, 1994, Commission File No. 1-10654).

10.35 Sixth Supplemental Indenture dated as of July 1, 1995, between Midwest Power Systems
Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.15
to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended
December 31, 1995, Commission File No. 1-11505).

10.36 Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947 (incorporated by
reference to Exhibit 7B filed by Iowa-Illinois Gas and Electric Company as part of
Commission File No. 2-6922).

10.37 Sixth Supplemental Indenture dated as of July 1, 1967 (incorporated by reference to Exhibit
2.08 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No.
2-28806).

10.38 Twentieth Supplemental Indenture dated as of May 1, 1982 (incorporated by reference to
Exhibit 4.B.23 to the Iowa-Illinois Gas and Electric Company Quarterly Report on Form
10-Q for the period ended June 30, 1982, Commission File No. 1-3573).

II-6

EXHIBIT NO. DESCRIPTION
- ------------- --------------------------------------------------------------------------------------------

10.40 Twenty-Eighth Supplemental Indenture dated as of May 15, 1992 (incorporated by
reference to Exhibit 4.31.B to the Iowa-Illinois Gas and Electric Company Current Report
on Form 8-K dated May 21, 1992, Commission File No. 1-3573).

10.41 Twenty-Ninth Supplemental Indenture dated as of March 15, 1993 (incorporated by
reference to Exhibit 4.32.A to the Iowa-Illinois Gas and Electric Company Current Report
on Form 8-K dated March 24, 1993, Commission File No. 1-3573).

10.42 Thirtieth Supplemental Indenture dated as of October 1, 1993 (incorporated by reference
to Exhibit 4.34.A to the Iowa-Illinois Gas and Electric Company Current Report on Form
8-K dated October 7, 1993, Commission File No. 1-3573).

10.43 Thirty-First Supplemental Indenture dated as of July 1, 1995, between Iowa-Illinois Gas and
Electric Company and Harris Trust and Savings Bank, Trustee (incorporated by reference
to Exhibit 4.16 to the MidAmerican Energy Company Annual Report on Form 10-K for the
year ended dated December 31, 1995, Commission File No. 1-11505).

10.44 Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated
September 22, 1967 (incorporated by reference to Exhibit 4-C-2 filed by Iowa Power Inc. as
part of Registration Statement No. 2-27681).

10.45 Amendments Nos. 1 and 2 to Power Sales Contract between Iowa Power Inc. and Nebraska
Public Power District (incorporated by reference to Exhibit 4-C-2a filed by Iowa Power Inc.
as part of Registration Statement No. 2-35624).

10.46 Amendment No. 3 dated August 31, 1970, to the Power Sales Contract between Iowa Power
Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by
reference to Exhibit 5-C-2-b filed by Iowa Power Inc. as part of Registration Statement No.
2-42191).

10.47 Amendment No. 4 dated March 28, 1974, to the Power Sales Contract between Iowa Power
Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by
reference to Exhibit 5-C-2-c filed by Iowa Power Inc. as part of Registration Statement No.
2-51540).

10.48 Amendment No. 5 dated September 2, 1997, to the Power Sales Contract between
MidAmerican Energy Company and Nebraska Public Power District, dated September 22,
1967 (incorporated by reference to Exhibit 10.2 to the former MidAmerican Energy
Holdings Company and MidAmerican Energy Company respective Quarterly Reports on
the combined Form 10-Q for the quarter ended September 30, 1997, Commission File Nos.
333-90553 and 1-11505, respectively).

10.49 Amendment No. 6 dated July 31, 2002, to the Power Sales Contract between MidAmerican
Energy Company and Nebraska Public Power District, dated September 22, 1967
(incorporated by reference to Exhibit 10.1 to the MidAmerican Funding, LLC and
MidAmerican Energy Company respective Quarterly Reports on the combined Form 10-Q
for the quarter ended June 20, 2002, Commission File Nos. 1-12459 and 1-11505,
respectively).

10.50 CalEnergy Company, Inc. Voluntary Deferred Compensation Plan effective December 1,
1997, First Amendment dated as of August 17, 1999 and Second Amendment effective
March 2000.

II-7

EXHIBIT NO. DESCRIPTION
- ------------- ---------------------------------------------------------------------------------------------

10.51 MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation
Plan.

10.52 MidAmerican Energy Company First Amended and Restated Supplemental Retirement
Plan for Designated Officers dated as of May 10, 1999.

10.53 MidAmerican Energy Company Restated Executive Deferred Compensation Plan
(incorporated by reference to Exhibit 10.6 to the Company's Annual Report on Form
10-K/A for the year ended December 31, 1999).

10.54 MidAmerican Energy Holdings Company Restated Deferred Compensation Plan--Board
of Directors (incorporated by reference to Exhibit 10 to the Company's Quarterly Report
on Form 10-Q for the quarter ended June 30, 1999).

10.55 MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated
Deferred Compensation Plan--Board of Directors (incorporated by reference to Exhibit
10.63 to the Company's Annual Report on Form 10-K/A for the year ended December 31,
1999).

10.56 Midwest Resources Inc. Supplemental Retirement Plan (formerly the Midwest Energy
Company Supplemental Retirement Plan (incorporated by reference to Exhibit 10.10 to the
Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31,
1993, Commission File No. 1-10654).

10.57 Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement Plan
(incorporated by reference to Exhibit 10.24 to the Midwest Resources Inc. Annual Report
on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).

10.58 Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan for Designated
Officers, as amended as of July 28, 1994 (incorporated by reference to the Iowa-Illinois Gas
and Electric Company Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-3573).

10.59 Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Designated
Officers, as amended as of July 1, 1993 (incorporated by reference to Exhibit 10.K.2 to the
Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended
December 31, 1993, Commission File No. 1-3573).

10.60 Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Key Employees,
dated as of April 26, 1991 (incorporated by reference to the Iowa-Illinois Gas and Electric
Company Annual Report on Form 10-K for the year ended December 31, 1991, Commission
File No. 1-3573).

10.61 Iowa-Illinois Gas and Electric Company Board of Directors' Compensation Deferral Plan
(incorporated by reference to Exhibit 10.K.4 to the Iowa-Illinois Gas and Electric Company
Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No.
1-3573).

10.62 Iowa Utilities Board Settlement Agreement among MidAmerican Energy Company, Office
of Consumer Advocate, Iowa Energy Consumers, Aluminum Company of America, Deere
& Company, Cargill Inc., U.S. Gypsum Company, Interstate Power Company and IES
Utilities, Inc. (incorporated by reference to Exhibit 10.16 to the MidAmerican Funding,
LLC and MidAmerican Energy Company respective Annual Reports on the combined
Form 10-K for the year ended December 31, 2000, Commission File Nos. 333-90553 and
1-11505, respectively).

10.63 Share Sale Agreement among NPower Yorkshire Limited, Innogy Holdings plc, CE Electric
UK plc and Northern Electric plc dated as of August 6, 2001.

II-8

EXHIBIT NO. DESCRIPTION
- ------------- -------------------------------------------------------------------------------------------

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

10.65 Stock Purchase Agreement among The Williams Companies, Inc., MEHC Investment, Inc.
and the Company dated as of March 7, 2002 (incorporated by reference to Exhibit 99.3 to
the Company's Current Report on Form 8-K dated March 28, 2002).

10.66 Completion Guarantee given by the Company to Union Bank of California, Administrative
Agent, dated as of June 21, 2002 (incorporated by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K dated June 27, 2002).

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

12.1 Statement regarding Computation of Earnings to Fixed Charges.

15.1 Awareness Letter of Independent Accountants.

21.1 Subsidiaries of the Registrant.

23.1 Consent of Willkie Farr & Gallagher (included in their opinions filed as Exhibits 5.1 and
Exhibit 8.1).*

23.2 Consent of Deloitte & Touche LLP.

24.1 Powers of Attorney (included on the signature pages hereto).

25.1 Statement on Form T-1 of Eligibility of Trustee relating to the 4.625% Senior Notes due
2007 and the 5.875% Senior Notes due 2012.

99.1 Form of Letter of Transmittal relating to the 4.625% Senior Notes due 2007.

99.2 Form of Notice of Guaranteed Delivery relating to the 4.625% Senior Notes due 2007.

99.3 Form of Letter to Clients relating to the 4.625% Senior Notes due 2007.

99.4 Form of Letter to Nominees relating to the 4.625% Senior Notes due 2007.

99.5 Form of Letter of Transmittal relating to the 5.875% Senior Notes due 2012.

99.6 Form of Notice of Guaranteed Delivery relating to the 5.875% Senior Notes due 2012.

99.7 Form of Letter to Clients relating to the 5.875% Senior Notes due 2012.

99.8 Form of Letter to Nominees relating to the 5.875% Senior Notes due 2012.

(b) Financial Statement Schedules

Schedule I--Condensed Financial Statements (MidAmerican Energy Holdings
Company only)

Schedule II--Consolidated Valuation and Qualifying Accounts

- ----------

* To be filed by amendment.

II-9

ITEM 22. UNDERTAKINGS.

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

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

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities
Act, the information omitted from the form of prospectus filed as part of
this registration statement in reliance upon Rule 430A and contained in a
form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or
497(h) under the Securities Act shall be deemed to be part of this
registration statement as of the time it was declared effective.

(2) For purposes of determining any liability under the Securities
Act, each post-effective amendment that contains a form of prospectus shall
be deemed to be a new registration statement relating to the securities
offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.

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

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

II-10

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended,
the registrant has duly caused this registration statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Des
Moines, State of Iowa, on the 6th day of December, 2002.

MIDAMERICAN ENERGY HOLDINGS COMPANY

By: /s/ David L. Sokol
----------------------------------------------
David L. Sokol
Chairman of the Board of Directors and
Chief Executive Officer

POWER OF ATTORNEY

The undersigned officers and directors of MidAmerican Energy Holdings
Company hereby severally constitute and appoint Douglas L. Anderson and Paul J.
Leighton, and each of them, attorneys-in-fact for the undersigned, in any and
all capacities, with the power of substitution, to sign any amendments to this
registration statement (including post-effective amendments) and any subsequent
registration statement for the same offering which may be filed under Rule
462(b) under the Securities Act of 1933, as amended, and to file the same with
exhibits thereto and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorneys-in-fact, and
each of them, full power and authority to do and perform each and every act and
thing requisite and necessary to be done in and about the premises, as fully
and to all interests and purposes as he might or could do in person, hereby
ratifying and confirming all that each said attorney-in-fact, or his substitute
or substitutes, may do or cause to be done by virtue thereof.

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

SIGNATURE TITLE DATE
- -------------------------------- -------------------------------- ----------------

/s/ David L. Sokol Chairman of the Board of December 6, 2002
----------------------------- Directors, Chief Executive
David L. Sokol Officer and Director (principal
executive officer)

/s/ Patrick J. Goodman Senior Vice President and December 6, 2002
----------------------------- Chief Financial Officer
Patrick J. Goodman (principal financial and
accounting officer)

/s/ Gregory E. Abel Director December 6, 2002
-----------------------------
Gregory E. Abel

II-11

SIGNATURE TITLE DATE
- -------------------------------- ---------- ----------------

/s/ Edgar D. Aronson Director December 6, 2002
-----------------------------
Edgar D. Aronson

/s/ John K. Boyer Director December 6, 2002
-----------------------------
John K. Boyer

/s/ Stanley J. Bright Director December 6, 2002
-----------------------------
Stanley J. Bright

/s/ Warren E. Buffett Director December 6, 2002
-----------------------------
Warren E. Buffett

/s/ Marc D. Hamburg Director December 6, 2002
-----------------------------
Marc D. Hamburg

/s/ Richard R. Jaros Director December 6, 2002
-----------------------------
Richard R. Jaros

/s/ W. David Scott Director December 6, 2002
-----------------------------
W. David Scott

/s/ Walter Scott, Jr. Director December 6, 2002
-----------------------------
Walter Scott, Jr.

II-12

MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
As of December 31, 2001 and 2000
(In thousands)

2001 2000
-------------- --------------

ASSETS
Current Assets:
Cash and cash equivalents ............................................. $ 2,524 $ 8,223
---------- ----------
Total current assets ................................................. 2,524 8,223
Investments in and advances to subsidiaries and joint ventures ......... 3,432,528 3,125,487
Equipment, net ......................................................... 17,605 17,228
Excess of cost over fair value of net assets acquired, net ............. 1,211,814 1,216,550
Deferred charges and other assets ...................................... 129,501 127,966
---------- ----------
Total Assets ........................................................... $4,793,972 $4,495,454
========== ==========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and other accrued liabilities ........................ $ 68,445 $ 54,073
Short term debt ....................................................... 153,500 85,000
---------- ----------
Total current liabilities ............................................ 221,945 139,073
Non-current liabilities ................................................ 6,480 6,435
Notes payable -- affiliate ............................................. 197,153 122,177
Parent company debt .................................................... 1,834,498 1,829,971
---------- ----------
Total liabilities ..................................................... 2,260,076 2,097,656
---------- ----------

Deferred income ........................................................ 37,578 34,874
Company-obligated mandatorily redeemable preferred securities of
subsidiary trusts ..................................................... 788,151 786,523

Stockholders' Equity:
Zero coupon convertible preferred stock -- authorized 50,000 shares,
no par value, 34,563 shares issued and outstanding at December 31,
2001 and 2000 ......................................................... -- --
Common stock -- authorized 60,000 shares, no par value; 9,281 shares
issued and outstanding at December 31, 2001 and 2000 .................. -- --
Additional paid in capital ............................................. 1,553,073 1,553,073
Retained earnings ...................................................... 223,926 81,257
Accumulated other comprehensive loss, net .............................. (68,832) (57,929)
---------- ----------
Total stockholders' equity ............................................. 1,708,167 1,576,401
---------- ----------

Total Liabilities and Stockholders' Equity ............................. $4,793,972 $4,495,454
========== ==========

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

S-1

MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF OPERATIONS
For the three years ended December 31, 2001
(In thousands)

2001 2000 1999
----------- ----------- -----------

Revenue:
Equity in undistributed earnings of subsidiary companies
and joint ventures ....................................... $608,896 $390,194 $ 166,428
Cash dividends and distributions from subsidiary
companies and joint ventures ............................. 87,625 96,342 345,430
Interest and other income ................................. 2,248 13,818 34,002
-------- -------- ---------

Total revenues ........................................... 698,769 500,354 545,860
-------- -------- ---------

Expenses:

General and administration ................................ 41,078 45,089 39,174
Depreciation and amortization ............................. 31,537 25,716 1,088
Interest, net of capitalized interest ..................... 148,680 141,891 163,589
-------- -------- ---------

Total expenses ........................................... 221,295 212,696 203,851
-------- -------- ---------

Income before provision for income taxes .................. 477,474 287,658 342,009
Provision for income taxes ................................ 250,064 84,285 93,475
-------- -------- ---------

Income before minority interest ........................... 227,410 203,373 248,534
Minority interest ......................................... 80,137 70,804 31,863
-------- -------- ---------

Income before extraordinary items and cumulative effect
of change in accounting principle ........................ 147,273 132,569 216,671
Extraordinary items, net of tax ........................... -- -- (49,441)
Cumulative effect of change in accounting principle, net of
tax ...................................................... (4,604) -- --
-------- -------- ---------
Net income available to common stockholders ............... $142,669 $132,569 $ 167,230
======== ======== =========

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

S-2

MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF CASH FLOWS
For the three years ended December 31, 2001
(In thousands)

2001 2000 1999
--------------- --------------- ---------------

Cash flows from operating activities .......................... $ (272,906) $ (299,862) $ (261,276)
----------- ------------ ------------

Cash flows from investing activities:
Decrease (increase) in advances to and investments in
subsidiaries and joint ventures .............................. 204,118 143,052 (53,215)
Acquisition of MEHC (Predecessor) ............................. -- (2,048,266) --
Other ......................................................... (5,297) 28,458 (4,390)
----------- ------------ ------------
Cash flows from investing activities .......................... 198,821 (1,876,756) (57,605)
----------- ------------ ------------

Cash flows from financing activities:
Proceeds from issuance of common and preferred stock .......... -- 1,428,024 --
Proceeds from issuance of trust preferred securities .......... -- 454,772 --
Repayments of parent company debt ............................. (32) -- (853,420)
Net proceeds from revolver .................................... 68,500 85,000 --
Purchase of treasury stock .................................... -- -- (104,847)
Other ......................................................... (82) (23,893) (4,208)
----------- ------------ ------------

Cash flows from financing activities .......................... 68,386 1,943,903 (962,475)
----------- ------------ ------------

Net increase (decrease) in cash and cash equivalents .......... (5,699) (232,715) (1,281,356)

Cash and cash equivalents at beginning of period .............. 8,223 240,938 1,522,294
----------- ------------ ------------

Cash and cash equivalents at end of period .................... $ 2,524 $ 8,223 $ 240,938
----------- ------------ ------------

Supplemental disclosures:

Interest paid (net of amount capitalized) ..................... $ 148,999 $ 144,147 $ 180,274
=========== ============ ============

Income taxes paid ............................................. $ 133,139 $ 94,405 $ 130,875
=========== ============ ============

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

S-3

SCHEDULE II
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2001
(IN THOUSANDS)

COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------- ------------ ---------------------- ------------- -----------
ADDITIONS
BALANCE AT ---------------------- BALANCE AT
BEGINNING CHARGED OTHER END
DESCRIPTION OF YEAR TO INCOME ACCOUNTS DEDUCTIONS OF YEAR
- ----------- ------------ ----------- ---------- ------------- -----------

Reserves Deducted From Assets
To Which They Apply:

Reserve for uncollectible accounts receivable:

Year ended 2001 ............................ $ 32,685 $ 17,061 $ -- $ (42,427) $ 7,319
======== ======== ====== ========= =======

Year ended 2000 ............................ $ 18,666 $ 40,024 $ -- $ (26,005) $32,685
======== ======== ====== ========= =======

Year ended 1999 ............................ $ 11,994 $ 14,483 $ -- $ (7,811) $18,666
======== ======== ====== ========= =======

Reserves Not Deducted From Assets (1):

Year ended 2001 ............................ $ 25,063 $ 5,046 $ -- $ (16,478) $13,631
======== ======== ====== ========= =======

Year ended 2000 ............................ $ 17,696 $ 10,832 $ -- $ (3,465) $25,063
======== ======== ====== ========= =======

Year ended 1999 ............................ $ 5,660 $ 15,112 $2,148 $ (5,224) $17,696
======== ======== ====== ========= =======

- ----------

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

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

S-4

INDEX TO EXHIBITS

EXHIBIT NO. DESCRIPTION
- ------------- --------------------------------------------------------------------------------------------

3.1 Amended and Restated Articles of Incorporation of the Company effective March 6, 2002.
(incorporated by reference to Exhibit 3.3 to the Company's Annual Report on Form 10-K
for the year ended December 31, 2001).
3.2 Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Annual
Report on Form 10-K/A for the year ended December 31, 1999).
4.1 Indenture, dated as of October 4, 2002, by and between the Company and The Bank of New York,
relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012.
4.2 First Supplemental Indenture, dated as of October 4, 2002, by and between the Company and
The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior
Notes due 2012.
4.3 Registration Rights Agreement, dated as of October 1, 2002, by and between the Company and
Credit Suisse First Boston (as Representative for the Initial Purchasers).
4.4 Indenture for the 6 1/4% Convertible Junior Subordinated Debentures due 2012, dated as
of February 26, 1997, between the Company, as issuer, and the Bank of New York, as
Trustee (incorporated by reference to Exhibit 10.129 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1995).
4.5 Indenture, dated as of October 15, 1997, among the Company and IBJ Schroder Bank &
Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to the Company's
Current Report on Form 8-K dated October 23, 1997).
4.6 Form of First Supplemental Indenture for the 7.63% Senior Notes in the principal amount
of $350,000,000 due 2007, dated as of October 28, 1997, among the Company and IBJ
Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to
the Company's Current Report on Form 8-K dated October 23, 1997).
4.7 Form of Second Supplemental Indenture for the 6.96% Senior Notes in the principal
amount of $215,000,000 due 2003, 7.23% Senior Notes in the principal amount of
$260,000,000 due 2005, 7.52% Senior Notes in the principal amount of $450,000,000 due
2008, and 8.48% Senior Notes in the principal amount of $475,000,000 due 2028, dated as of
September 22, 1998 between the Company and IBJ Schroder Bank & Trust Company, as
Trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on
Form 8-K dated September 17, 1998.)
4.8 Form of Third Supplemental Indenture for the 7.52% Senior Notes in the principal amount
of $100,000,000 due 2008, dated as of November 13, 1998, between the Company and IBJ
Schroder Bank & Trust Company, as Trustee (incorporated by reference to the Company's
Current Report on Form 8-K dated November 10, 1998).
4.9 Indenture, dated as of March 14, 2000, among the Company and the Bank of New York, as
Trustee (incorporated by reference to Exhibit 4.9 to the Company's Annual Report on
Form 10-K/A for the year ended December 31, 1999).
4.10 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 14, 2000
(incorporated by reference to Exhibit 4.10 to the Company's Annual Report on Form
10-K/A for the year ended December 31, 1999).

EXHIBIT NO. DESCRIPTION
- ------------- -----------------------------------------------------------------------------------------

4.11 Indenture, dated as of March 12, 2002 between the Company and the Bank of New York,
as Trustee (incorporated by reference to Exhibit 4.11 to the Company's Annual Report on
Form 10-K for the year ended December 31, 2001).
4.12 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 7, 2002
(incorporated by reference to Exhibit 4.12 to the Company's Annual Report on Form 10-K
for the year ended December 31, 2001).
4.13 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 12, 2002
(incorporated by reference to Exhibit 4.13 to the Company's Annual Report on Form 10-K
for the year ended December 31, 2001).
4.14 Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of
August 16, 2002.
4.15 Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of
March 12, 2002.
4.16 Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of
March 14, 2000.
4.17 Indenture, dated as of August 16, 2002 between the Company and the Bank of New York,
as Trustee.
4.18 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of August 16, 2002.
4.19 Shareholders Agreement by and among Berkshire Hathaway, the Scott Family Entities,
David L. Sokol, Gregory E. Abel and Teton Acquisition Corp., dated as of March 14, 2000.
5.1 Opinion of Willkie Farr & Gallagher.*
8.1 Opinion of Willkie Farr & Gallagher with respect to certain tax matters.*
10.1 Employment Agreement between the Company and David L. Sokol, dated May 10, 1999
(incorporated by reference to Exhibit 10.1 to the Company's Annual Report on Form
10-K/A for the year ended December 31, 1999).
10.2 Amendment No. 1 to the Amended and Restated Employment Agreement between the
Company and David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit
10.2 to the Company's Annual Report on Form 10-K/A for the year ended December 31,
1999).
10.3 Non-Qualified Stock Options Agreements of David L. Sokol dated March 14, 2000.
10.4 Amended and Restated Employment Agreement between the Company and Gregory E.
Abel, dated May 10, 1999 (incorporated by reference to Exhibit 10.3 to the Company's
Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.5 Non-Qualified Stock Options Agreements of Gregory E. Abel dated March 14, 2000.
10.6 Employment Agreement between the Company and Patrick J. Goodman, dated April 21,
1999 (incorporated by reference to Exhibit 10.5 to the Company's Annual Report on Form
10-K/A for the year ended December 31, 1999).
10.7 MidAmerican Energy Holdings Company Long Term Incentive Partnership Plan.

EXHIBIT NO. DESCRIPTION
- ------------- ---------------------------------------------------------------------------------------------

10.8 125 MW Power Plant--Upper Mahiao Agreement dated September 6, 1993 between
PNOC-Energy Development Corporation and Ormat, Inc. as amended by the First
Amendment to 125 MW Power Plant Upper Mahiao Agreement dated as of January 28,
1994, the Letter Agreement dated February 10, 1994, the Letter Agreement dated
February 18, 1994 and the Fourth Amendment to 125 MW Power Plant--Upper Mahiao
Agreement dated as of March 7, 1994 (incorporated by reference to Exhibit 10.95 to the
Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.9 Credit Agreement dated April 8, 1994 among CE Cebu Geothermal Power Company, Inc.,
the Banks thereto, Credit Suisse as Agent (incorporated by reference to Exhibit 10.96 to the
Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.10 Credit Agreement dated as of April 8, 1994 between CE Cebu Geothermal Power
Company, Inc., Export-Import Bank of the United States (incorporated by reference to
Exhibit 10.97 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).
10.11 Pledge Agreement among CE Philippines Ltd, Ormat-Cebu Ltd., Credit Suisse as Collateral
Agent and CE Cebu Geothermal Power Company, Inc. dated as of April 8, 1994
(incorporated by reference to Exhibit 10.98 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1993).
10.12 Overseas Private Investment Corporation Contract of Insurance dated April 8, 1994
between the Overseas Private Investment Corporation and the Company through its
subsidiaries CE International Ltd., CE Philippines Ltd., and Ormat-Cebu Ltd. (incorporated
by reference to Exhibit 10.99 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1993).
10.13 180 MW Power Plant--Mahanagdong Agreement dated September 18, 1993 between
PNOC-Energy Development Corporation and CE Philippines Ltd. and the Company, as
amended by the First Amendment to Mahanagdong Agreement dated June 22, 1994, the
Letter Agreement dated July 12, 1994, the Letter Agreement dated July 29, 1994, and the
Fourth Amendment to Mahanagdong Agreement dated March 3, 1995 (incorporated by
reference to Exhibit 10.100 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1993).
10.14 Credit Agreement dated as of June 30, 1994 among CE Luzon Geothermal Power
Company, Inc., American Pacific Finance Company, the Lenders party thereto, and Bank of
America National Trust and Savings Association as Administrative Agent (incorporated by
reference to Exhibit 10.101 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1993).
10.15 Credit Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power
Company, Inc. and Export-Import Bank of the United States (incorporated by reference to
Exhibit 10.102 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).
10.16 Finance Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power
Company, Inc. and Overseas Private Investment Corporation (incorporated by reference to
Exhibit 10.103 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).

EXHIBIT NO. DESCRIPTION
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10.17 Pledge Agreement dated as of June 30, 1994 among CE Mahanagdong Ltd., Kiewit Energy
International (Bermuda) Ltd., Bank of America National Trust and Savings Association as
Collateral Agent and CE Luzon Geothermal Power Company, Inc. (incorporated by
reference to Exhibit 10.104 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1993).
10.18 Overseas Private Investment Corporation Contract of Insurance dated July 29, 1994
between Overseas Private Investment Corporation and the Company, CE International
Ltd., CE Mahanagdong Ltd. and American Pacific Finance Company and Amendment No.
1 dated August 3, 1994 (incorporated by reference to Exhibit 10.105 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1993).
10.19 231 MW Power Plant--Malitbog Agreement dated September 10, 1993 between PNOC-
Energy Development Corporation and Magma Power Company and the First and Second
Amendments thereto dated December 8, 1993 and March 10, 1994, respectively (incorporated
by reference to Exhibit 10.106 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1993).
10.20 Credit Agreement dated as of November 10, 1994 among Visayas Power Capital Corporation,
the Banks parties thereto and Credit Suisse Bank Agent (incorporated by reference to
Exhibit 10.107 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).
10.21 Finance Agreement dated as of November 10, 1994 between Visayas Geothermal Power
Company and Overseas Private Investment Corporation (incorporated by reference to
Exhibit 10.108 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).
10.22 Pledge and Security Agreement dated as of November 10, 1994 among Broad Street
Contract Services, Inc., Magma Power Company, Magma Netherlands B.V. and Credit
Suisse as Bank Agent (incorporated by reference to Exhibit 10.109 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1993).
10.23 Overseas Private Investment Corporation Contract of Insurance dated December 21, 1994
between Overseas Private Investment Corporation and Magma Netherlands, B.V.
(incorporated by reference to Exhibit 10.110 to the Company's Annual Report on Form
10-K for the year ended December 31, 1993).
10.24 Agreement as to Certain Common Representations, Warranties, Covenants and Other
Terms, dated November 10, 1994 between Visayas Geothermal Power Company, Visayas
Power Capital Corporation, Credit Suisse, as Bank Agent, Overseas Private Investment
Corporation and the Banks named therein (incorporated by reference to Exhibit 10.111 to
the Company's 1994 Annual Report on Form 10-K for the year ended December 31, 1993).
10.25 Trust Indenture dated as of November 27, 1995 between the CE Casecnan Water and
Energy Company, Inc. and Chemical Trust Company of California (incorporated by
reference to Exhibit 4.1 to CE Casecnan Water and Energy Company, Inc.'s Registration
Statement on Form S-4 dated January 25, 1996).
10.26 Amended and Restated Casecnan Project Agreement between the National Irrigation
Administration and CE Casecnan Water and Energy Company Inc. dated June 26, 1995
(incorporated by reference to Exhibit 10.1 to CE Casecnan Water and Energy Company,
Inc.'s Registration Statement on Form S-4 dated January 25, 1996).

EXHIBIT NO. DESCRIPTION
- ------------- --------------------------------------------------------------------------------------------

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

EXHIBIT NO. DESCRIPTION
- ------------- --------------------------------------------------------------------------------------------

10.39 Resignation and Appointment of successor Individual Trustee (incorporated by reference
to Exhibit 4.B.30 filed by Iowa-Illinois Gas and Electric Company as part of Commission
File No. 33-39211).
10.40 Twenty-Eighth Supplemental Indenture dated as of May 15, 1992 (incorporated by
reference to Exhibit 4.31.B to the Iowa-Illinois Gas and Electric Company Current Report
on Form 8-K dated May 21, 1992, Commission File No. 1-3573).
10.41 Twenty-Ninth Supplemental Indenture dated as of March 15, 1993 (incorporated by
reference to Exhibit 4.32.A to the Iowa-Illinois Gas and Electric Company Current Report
on Form 8-K dated March 24, 1993, Commission File No. 1-3573).
10.42 Thirtieth Supplemental Indenture dated as of October 1, 1993 (incorporated by reference
to Exhibit 4.34.A to the Iowa-Illinois Gas and Electric Company Current Report on Form
8-K dated October 7, 1993, Commission File No. 1-3573).
10.43 Thirty-First Supplemental Indenture dated as of July 1, 1995, between Iowa-Illinois Gas and
Electric Company and Harris Trust and Savings Bank, Trustee (incorporated by reference
to Exhibit 4.16 to the MidAmerican Energy Company Annual Report on Form 10-K for the
year ended dated December 31, 1995, Commission File No. 1-11505).
10.44 Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated
September 22, 1967 (incorporated by reference to Exhibit 4-C-2 filed by Iowa Power Inc. as
part of Registration Statement No. 2-27681).
10.45 Amendments Nos. 1 and 2 to Power Sales Contract between Iowa Power Inc. and Nebraska
Public Power District (incorporated by reference to Exhibit 4-C-2a filed by Iowa Power Inc.
as part of Registration Statement No. 2-35624).
10.46 Amendment No. 3 dated August 31, 1970, to the Power Sales Contract between Iowa Power
Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by
reference to Exhibit 5-C-2-b filed by Iowa Power Inc. as part of Registration Statement No.
2-42191).
10.47 Amendment No. 4 dated March 28, 1974, to the Power Sales Contract between Iowa Power
Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by
reference to Exhibit 5-C-2-c filed by Iowa Power Inc. as part of Registration Statement No.
2-51540).
10.48 Amendment No. 5 dated September 2, 1997, to the Power Sales Contract between
MidAmerican Energy Company and Nebraska Public Power District, dated September 22,
1967 (incorporated by reference to Exhibit 10.2 to the former MidAmerican Energy
Holdings Company and MidAmerican Energy Company respective Quarterly Reports on
the combined Form 10-Q for the quarter ended September 30, 1997, Commission File Nos.
333-90553 and 1-11505, respectively).
10.49 Amendment No. 6 dated July 31, 2002, to the Power Sales Contract between MidAmerican
Energy Company and Nebraska Public Power District, dated September 22, 1967
(incorporated by reference to Exhibit 10.1 to the MidAmerican Funding, LLC and
MidAmerican Energy Company respective Quarterly Reports on the combined Form 10-Q
for the quarter ended June 20, 2002, Commission File Nos. 1-12459 and 1-11505,
respectively).
10.50 CalEnergy Company, Inc. Voluntary Deferred Compensation Plan effective December 1,
1997, First Amendment dated as of August 17, 1999 and Second Amendment effective
March 2000.

EXHIBIT NO. DESCRIPTION
- ------------- ---------------------------------------------------------------------------------------------

10.51 MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation
Plan.
10.52 MidAmerican Energy Company First Amended and Restated Supplemental Retirement
Plan for Designated Officers dated as of May 10, 1999.
10.53 MidAmerican Energy Company Restated Executive Deferred Compensation Plan
(incorporated by reference to Exhibit 10.6 to the Company's Annual Report on Form
10-K/A for the year ended December 31, 1999).
10.54 MidAmerican Energy Holdings Company Restated Deferred Compensation Plan--Board
of Directors (incorporated by reference to Exhibit 10 to the Company's Quarterly Report
on Form 10-Q for the quarter ended June 30, 1999).
10.55 MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated
Deferred Compensation Plan--Board of Directors (incorporated by reference to Exhibit
10.63 to the Company's Annual Report on Form 10-K/A for the year ended December 31,
1999).
10.56 Midwest Resources Inc. Supplemental Retirement Plan (formerly the Midwest Energy
Company Supplemental Retirement Plan (incorporated by reference to Exhibit 10.10 to the
Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31,
1993, Commission File No. 1-10654).
10.57 Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement Plan
(incorporated by reference to Exhibit 10.24 to the Midwest Resources Inc. Annual Report
on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
10.58 Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan for Designated
Officers, as amended as of July 28, 1994 (incorporated by reference to the Iowa-Illinois Gas
and Electric Company Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-3573).
10.59 Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Designated
Officers, as amended as of July 1, 1993 (incorporated by reference to Exhibit 10.K.2 to the
Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended
December 31, 1993, Commission File No. 1-3573).
10.60 Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Key Employees,
dated as of April 26, 1991 (incorporated by reference to the Iowa-Illinois Gas and Electric
Company Annual Report on Form 10-K for the year ended December 31, 1991, Commission
File No. 1-3573).
10.61 Iowa-Illinois Gas and Electric Company Board of Directors' Compensation Deferral Plan
(incorporated by reference to Exhibit 10.K.4 to the Iowa-Illinois Gas and Electric Company
Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No.
1-3573).
10.62 Iowa Utilities Board Settlement Agreement among MidAmerican Energy Company, Office
of Consumer Advocate, Iowa Energy Consumers, Aluminum Company of America, Deere
& Company, Cargill Inc., U.S. Gypsum Company, Interstate Power Company and IES
Utilities, Inc. (incorporated by reference to Exhibit 10.16 to the MidAmerican Funding,
LLC and MidAmerican Energy Company respective Annual Reports on the combined
Form 10-K for the year ended December 31, 2000, Commission File Nos. 333-90553 and
1-11505, respectively).
10.63 Share Sale Agreement among NPower Yorkshire Limited, Innogy Holdings plc, CE Electric
UK plc and Northern Electric plc dated as of August 6, 2001.

EXHIBIT NO. DESCRIPTION
- ------------- -------------------------------------------------------------------------------------------

10.64 Purchase Agreement among The Williams Companies, Inc., Williams Gas Pipeline Company,
LLC, Williams Western Pipeline Company LLC, Kern River Acquisition, LLC and
MidAmerican Energy Holdings Company, KR Holding, LLC, Kr Acquisition 1, LLC and
KR Acquisition 2, LLC, dated as of March7, 2002 (incorporated by reference to Exhibit 99.2
to the Company's Current Report on Form 8-K dated March 28, 2002).
10.65 Stock Purchase Agreement among The Williams Companies, Inc., MEHC Investment, Inc.
and MidAmerican Energy Holdings Company dated as of March7, 2002 (incorporated by
reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated March 28,
2002).
10.66 Completion Guarantee given by MidAmerican Energy Holdings Company to Union Bank
of California, Administrative Agent, dated as of June 21, 2002 (incorporated by reference
to Exhibit 99.2 to the Company's Current Report on Form 8-K dated June 27, 2002).
10.67 Purchase and Sale Agreement between Dynegy Inc., NNGC Holding Company, Inc. and
MidAmerican Energy Holdings Company, dated as of July 28, 2002 (incorporated by
reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated July 30,
2002).
12.1 Statement regarding Computation of Earnings to Fixed Charges.
15.1 Awareness Letter of Independent Accountants.
21.1 Subsidiaries of the Registrant.
23.1 Consent of Willkie Farr & Gallagher (included in their opinions filed as Exhibits 5.1 and
Exhibit 8.1).*
23.2 Consent of Deloitte & Touche LLP.
24.1 Powers of Attorney (included on the signature pages hereto).
25.1 Statement on Form T-1 of Eligibility of Trustee relating to the 4.625% Senior Notes due
2007 and the 5.875% Senior Notes due 2012.
99.1 Form of Letter of Transmittal relating to the 4.625% Senior Notes due 2007.
99.2 Form of Notice of Guaranteed Delivery relating to the 4.625% Senior Notes due 2007.
99.3 Form of Letter to Clients relating to the 4.625% Senior Notes due 2007.
99.4 Form of Letter to Nominees relating to the 4.625% Senior Notes due 2007.
99.5 Form of Letter of Transmittal relating to the 5.875% Senior Notes due 2012.
99.6 Form of Notice of Guaranteed Delivery relating to the 5.875% Senior Notes due 2012.
99.7 Form of Letter to Clients relating to the 5.875% Senior Notes due 2012.
99.8 Form of Letter to Nominees relating to the 5.875% Senior Notes due 2012.

(b) Financial Statement Schedules

Schedule I--Condensed Financial Statements (MidAmerican Energy Holdings
Company only)

Schedule II--Consolidated Valuation and Qualifying Accounts

- ----------
* To be filed by amendment.