UNITED STATES

                       SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549

                                    FORM 10-K

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

                   For the fiscal year ended December 31, 2000

            [ ] Transition Report Pursuant to Section 13 or 15(d) of

                       the Securities Exchange Act of 1934

                      For the transition period from _____
                          to _____ Commission File No.

                                     0-25551

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

                                      Iowa

                                  ---- --------
                                   94-2213782

                (State or other jurisdiction of (I.R.S.  Employer  incorporation
               or organization) Identification No.)

                     666 Grand Avenue, Des Moines, IA     50309
                     --------------------------------     -----
               (Address of principal executive offices) (Zip Code)

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

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

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

         Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
Registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days:

                           Yes    X                  No
                              ----------               -----------

         Indicate by check mark if disclosure of delinquent  filers  pursuant to
Item 405 of Regulation  S-K is  not contained herein, and will not be contained,
to  the  best  of Registrant's  knowledge,  in definitive  proxy  or information
statements incorporated by reference in Part III of this Form 10-K or any amend-
ment to this Form 10-K.  [X]

         All of the shares of MidAmerican  Energy Holdings Company are held by a
limited group of private  investors.  As of March 30, 2001,  9,281,087 shares of
common stock were outstanding.

<PAGE>

                                TABLE OF CONTENTS

PART I.......................................................................4
Item 1. Business.............................................................4
General......................................................................4
Teton Transaction............................................................4
Business of MEHC.............................................................4
     MidAmerican Energy......................................................4
     Northern Electric.......................................................8
     CalEnergy Generation....................................................14
          Projects in Operation..............................................15
          CE Generation Geothermal Facilities................................15
          CE Generation Gas Facilities.......................................17
          Other U.S. Geothermal Interests....................................18
          The Philippines Power Generation...................................18
     Projects in Construction................................................20
          United States......................................................20
          Philippines........................................................21
     HomeServices............................................................23
The Global Energy Market.....................................................23
     United States...........................................................24
     United Kingdom..........................................................26
Regulatory, Energy and Environmental Matters.................................28
     United States...........................................................28
     United Kingdom..........................................................30
Employees....................................................................30
Item 2. Properties...........................................................31
Item 3. Legal Proceedings....................................................32
Item 4. Submission of Matters to a Vote of Security Holders..................33

PART II......................................................................34
Item 5. Market for Registrant's Common Equity and Related
          Stockholder's Matters..............................................34
Item 6. Selected Financial Data..............................................34
Item 7. Management's Discussion and Analysis of Financial
          Condition and Results of Operations................................34
Item 7A.Qualitative and Quantitative Disclosures About Market Risk...........34
Item 8. Financial Statements and Supplementary Data..........................34
Item 9. Changes in and Disagreements with Accountants on Accounting
          and Financial Disclosure...........................................34

PART III.....................................................................35
Item 10. Directors, Executive and Other Officers of the Company
          and Significant Subsidiaries.......................................35
Item 11. Executive Compensation..............................................36
Item 12. Security Ownership of Certain Beneficial Owners and Management......36
Item 13. Certain Relationships and Related Transactions......................36

PART IV......................................................................37
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.....37

SIGNATURES...................................................................100

EXHIBIT INDEX................................................................102


<PAGE>

                                     PART I

Item 1.  Business

General

MidAmerican  Energy  Holdings  Company (the  "Company"  or "MEHC"),  is a United
States based  privately  owned global energy company with publicly  traded fixed
income  securities.   Through  its  subsidiaries,   MidAmerican  Energy  Company
("MidAmerican  Energy") and  Northern  Electric  plc  ("Northern"),  the Company
currently serves approximately 1.8 million electricity customers and 1.1 million
natural gas customers  worldwide.  In addition,  through its  subsidiaries,  the
Company owns  interests in over 10,000  megawatts  ("MW") of  diversified  power
generation facilities in operation,  construction and development. The Company's
Senior  unsecured  obligations  have received  investment grade ratings of Baa3,
BBB- and BBB from Moody's Investor Services Inc.  ("Moody's"),  Standard & Poors
Ratings Services ("S&P") and Fitch ("Fitch"). The Company's utility subsidiaries
are also investment grade rated by Moody's,  S&P and Fitch:  MidAmerican  Energy
(A3, A- and A+) and Northern (A3, A- and A).

In this Annual Report,  references to "U.S.  dollars," "dollars," "US $," "$" or
"cents"  are to the  currency  of the United  States and  references  to "pounds
sterling",  "pounds,"  "sterling,"  "pence"  or "p" are to the  currency  of the
United Kingdom.

The principal  executive offices of the Company are located at 666 Grand Avenue,
Des Moines,  Iowa 50309 and its telephone number is (515) 242-4300.  The Company
was initially  incorporated in 1971 under the laws of the State of Delaware. The
Company was reincorporated in 1999 in Iowa.

Teton Transaction

On October 24, 1999,  the Company  entered into an Agreement  and Plan of Merger
with an investor group that included Berkshire Hathaway Inc., Walter Scott, Jr.,
and David L.  Sokol (the  "Investor  Group").  The  Investor  Group,  along with
Gregory  E.  Abel,  closed  on the  acquisition  on March 14,  2000 (the  "Teton
Transaction").  Pursuant to the acquisition,  the Investor Group,  including Mr.
Abel, paid the Company's  shareholders $35.05 in cash for each outstanding share
of the Company's common stock and became the sole shareholders of the Company in
a "going private" transaction.

Business of MEHC

The Company 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 four separate platforms:  MidAmerican Energy,  Northern Electric,
CalEnergy Generation and HomeServices.

MidAmerican Energy

MidAmerican  Energy is the largest energy company  headquartered  in Iowa,  with
assets and 2000 revenues  totaling $3.8 billion and $2.3 billion,  respectively.
MidAmerican   Energy  is  primarily  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.  As of December 31, 2000,
MidAmerican  Energy had 669,000  retail  electric  customers and 647,000  retail
natural gas customers.

<PAGE>

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.

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

MidAmerican Energy has a residential,  agricultural,  commercial and diversified
industrial customer group, in which no single industry or customer accounted for
more than 4% of its total 2000  electric  operating  revenues or 2% of its total
2000 gas operating  margin.  Among the primary  industries served by MidAmerican
Energy are those which are  concerned  with the  manufacturing,  processing  and
fabrication  of primary  metals,  real  estate,  food  products,  farm and other
non-electrical machinery, and cement and gypsum products.

For the year ended December 31, 2000,  MidAmerican Energy derived  approximately
52% of its gross operating revenues from its regulated  electric  business,  28%
from  its  regulated  gas  business  and  20%  from  its  nonregulated  business
activities.  For 1999 and 1998, the corresponding percentages were 66% electric,
25% gas and 9%  nonregulated;  and 69%  electric,  25% gas and 6%  nonregulated,
respectively.  The change in revenue  mix for 2000 was driven by an  increase in
natural gas prices and in nonregulated natural gas sales activity.

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.

A substantial  majority 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 also manages its  operations  as four distinct
business units: generation,  transmission, energy distribution and retail. It is
under this framework that  MidAmerican  Energy believes it can best prepare for,
and succeed in, the energy  business  of the  future.  With these four  business
units, MidAmerican Energy is able to focus on the specific needs and anticipated
risks  and  opportunities  of  its  major  businesses.   Certain  administrative
functions  are handled by a corporate  services  group that  supports all of the
business units.

Presently,  significant  functions of the  generation  business unit include the
production of electricity,  the purchase of electricity and natural gas, and the
sale of wholesale  electricity and natural gas. The  transmission  business unit
coordinates all activities related to MidAmerican Energy's electric transmission
facilities,  including  monitoring access to and assuring the reliability of the
transmission   system.  The  energy   distribution   business  unit  distributes
electricity and natural gas to end-users, provides customer service and conducts
related activities. Retail includes marketing and related functions for core and
complementary products and services.

<PAGE>

Historical electric sales by customer class as a percent of total electric sales
and retail  electric  sales data by state as a percent of total retail  electric
sales are shown below:

          Total Electric Sales of MidAmerican Energy By Customer Class

                                               2000       1999        1998

Residential                                    20.7%      21.0%       22.2%
Small General Service                          15.9       16.7        17.5
Large General Service                          28.6       26.9        28.1
Other                                           5.4        4.5         4.4
Sales for Resale                               29.4       30.9        27.8
                                              -----      -----       -----
 Total                                        100.0%     100.0%      100.0%
                                              ======     ======      ======


              Retail Electric Sales of MidAmerican Energy By State

                                               2000          1999        1998

Iowa                                           89.3%         88.9%       88.4%
Illinois                                       10.0          10.4        10.9
South Dakota                                    0.7           0.7         0.7
                                              ------        ------      ------
 Total                                        100.0%        100.0%      100.0%
                                              ======        ======      ======

Historical gas sales, excluding transportation  throughput, by customer class as
a percent of total gas sales and by state as a percent of total retail gas sales
are shown below:

        Total Regulated Gas Sales of MidAmerican Energy By Customer Class

                                                 2000         1999        1998

Residential                                     64.0%         63.5%       62.0%
Small General Service                           31.8          32.2        33.2
Large General Service                            4.0           4.0         3.8
Other                                            0.2           0.3         1.0
                                                -----        ------       -----
TOTAL                                          100.0%        100.0%      100.0%
                                               ======        ======      ======


                 Retail Gas Sales of MidAmerican Energy By State

                                               2000           1999         1998

Iowa                                           78.0%          78.8%        79.0%
Illinois                                       10.2           10.3         10.2
South Dakota                                   11.0           10.1         10.1
Nebraska                                        0.8            0.8          0.7
                                              ------        ------        ------
TOTAL                                         100.0%         100.0%       100.0%
                                              ======         ======       ======

<PAGE>
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 2000, 38% of MidAmerican Energy's electric revenues
were  reported in the months of June,  July,  August and  September,  and 56% of
MidAmerican  Energy's  gas  revenues  were  reported  in the months of  January,
February, March and December.

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
September 2000,  MidAmerican  Energy recorded an hourly peak demand of 3,648 MW,
which is 185 MW less than  MidAmerican  Energy's  previous record hourly peak of
3,833 MW set in 1999.

<TABLE>
<CAPTION>
The following table sets out certain information  concerning various MidAmerican
Energy power projects:
<S>                          <C>         <C>        <C>         <C>             <C>

---------------------------- ----------- ---------- ----------- --------------- -------------
Project(1)                     Facility    Net MW     Fuel        Location        Commercial
                               Net MW      Owned(2)                               Operation
---------------------------- ----------- ---------- ----------- --------------- -------------
Council Bluffs Energy               131  131        Coal        Iowa            1954, 1958
  Center units 1 & 2
---------------------------- ----------- ---------- ----------- --------------- -------------
Council Bluffs Energy               675  534        Coal        Iowa            1978
  Center unit 3
---------------------------- ----------- ---------- ----------- --------------- -------------
Louisa Generation Station           700  616        Coal        Iowa            1983
---------------------------- ----------- ---------- ----------- --------------- -------------
Neal Generation Station             435  435        Coal        Iowa            1964, 1972
  units 1 & 2
---------------------------- ----------- ---------- ----------- --------------- -------------
Neal Generation Station             515  371        Coal        Iowa            1975
  unit 3
---------------------------- ----------- ---------- ----------- --------------- -------------
Neal Generation Station             624  261        Coal        Iowa            1979
  unit 4
---------------------------- ----------- ---------- ----------- --------------- -------------
Ottumwa Generation Station          716  372        Coal        Iowa            1981
---------------------------- ----------- ---------- ----------- --------------- -------------
Quad Cities Power Station         1,529  383        Nuclear     Illinois        1972
---------------------------- ----------- ---------- ----------- --------------- -------------
Riverside Generation                135  135        Coal        Iowa            1925-61
  Station
---------------------------- ----------- ---------- ----------- --------------- -------------
Combustion Turbines                 789  789        Gas         Iowa            1969-95
---------------------------- ----------- ---------- ----------- --------------- -------------
Moline Water Power                    3  3          Hydro       Illinois        1970
---------------------------- ----------- ---------- ----------- --------------- -------------
Cooper Nuclear Station(3)           758  379        Nuclear     Nebraska        1974
---------------------------- ----------- ---------- ----------- --------------- -------------
Portable Power Modules               56  56         Oil         Iowa            2000
---------------------------- ----------- ---------- ----------- --------------- -------------
Total                             7,066  4,465
---------------------------- ----------- ---------- ----------- --------------- -------------
</TABLE>
(1)The Company operates all such projects other  than Quad Cities Power Station,
Ottumwa Generation Station and Cooper Nuclear Station.
(2)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.
(3)Cooper is owned by the Nebraska Public Power District and the amount shown is
MidAmerican  Energy's entitlement (50%) of Cooper's  accredited capacity under a
power purchase agreement extending to the year 2004.

All of the coal-fired  generating  stations  operated by MidAmerican  Energy are
fueled by  low-sulfur,  western coal from the Powder River Basin and Hanna Basin
mines. The use of low-sulfur  western coal enables  MidAmerican Energy to comply
with the current acid rain  provisions  of the Clean Air Act  Amendments of 1990
("CAAA") without having to install additional costly emissions control equipment
at its generating stations or purchase additional emissions credits. MidAmerican
Energy's  coal supply  portfolio  includes  multiple  suppliers  and mines under
agreements  of  varying  term  and  quantity  flexibility.   MidAmerican  Energy
regularly monitors the western coal market, looking for opportunities to improve
its coal supply portfolio. MidAmerican Energy believes its sources of coal
supply are and will continue to be satisfactory.

<PAGE>
MidAmerican  Energy  can use both the  Union  Pacific  Railroad  ("UP")  and the
Burlington Northern and Santa Fe Railway ("BNSF") as originating carriers of its
coal supply.  Coal is delivered  directly to  MidAmerican  Energy's  Neal Energy
Center by UP and to Council Bluffs Energy Center  ("CBEC") by either UP or BNSF.
Coal for MidAmerican  Energy's Louisa and Riverside  Energy Centers is delivered
to an interchange  point by BNSF or up for  transportation to its destination by
the  I&M  Rail  Link.   MidAmerican  Energy  believes  its  coal  transportation
arrangements are adequate to meet its coal delivery needs.

MidAmerican  Energy uses  natural  gas and oil as fuel for peak demand  electric
generation,  transmission  support  and  standby  purposes.  These  sources  are
presently in adequate supply and available to meet MidAmerican Energy's needs.

MidAmerican  Energy is a 25% joint owner of Quad Cities  Generating  Station,  a
nuclear power plant.  MidAmerican  Energy has been advised by Exelon  Generation
Company,  LLC  ("Exelon"),  the joint owner and operator of Quad Cities Station,
that the majority of its uranium concentrate and uranium conversion requirements
for Quad  Cities  Station  through  2001 can be met under  existing  supplies or
commitments.  Exelon foresees no problem in obtaining the remaining requirements
now or obtaining future requirements. Exelon further advises that all enrichment
requirements have been contracted through 2004. Commitments for fuel fabrication
have been  obtained at least through 2006.  Exelon does not  anticipate  that it
will have  difficulty in contracting  for uranium  concentrates  for conversion,
enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station.

MidAmerican Energy's accredited net generating  capability in the summer of 2000
was 4,507 MW.  Accredited  net  generating  capability  represents the amount of
generation  available to meet the  requirements  on MidAmerican  Energy's energy
system,  net of the  effect of  capacity  purchases  and sales and  consists  of
Company-owned  generation  and  generation  under  a  long-term  power  purchase
contract.  The  net  generating  capability  at  any  time  may be  less  due to
regulatory   restrictions,   fuel   restrictions   and  generating  units  being
temporarily   out  of  service  for   inspection,   maintenance,   refueling  or
modifications.

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 ("MAPP").  MAPP is a voluntary  association of
electric utilities doing business in Iowa, Minnesota,  Nebraska and North Dakota
and portions of Illinois,  Montana,  South Dakota and Wisconsin and the Canadian
provinces of  Saskatchewan  and Manitoba.  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.

Each MAPP  participant  is  required to maintain  for  emergency  purposes a net
generating capability reserve of at least 15% above its system peak demand. If a
participant's  capability  reserve  falls  below  the 15%  minimum,  significant
penalties could be contractually  imposed by MAPP.  MidAmerican Energy's reserve
margin at peak demand for 2000 was approximately 25%.

Northern Electric

The operations of Northern Electric plc  ("Northern"),  an indirect wholly owned
subsidiary of the Company,  consist  primarily of the distribution and supply of
electricity,  supply of natural gas and other auxiliary businesses in the United
Kingdom.  Northern's  operations are seasonal in nature with a  disproportionate
percentage of revenues and earnings  historically  being earned in the Company's
first and fourth quarters.

<PAGE>
Northern  Electric  Distribution  Limited  ("NEDL"),  a subsidiary  of Northern,
receives  electricity from the national grid transmission system and distributes
electricity to each of its authorized area customer's  premises using Northern's
network  of  transformers,  switchgear  and  cables.  Substantially  all  of the
customers in Northern's  authorized area are connected to Northern's network and
electricity  can only be delivered  to them  through the  Northern  distribution
system,  regardless of whether the electricity is supplied by Northern's  supply
business or by other suppliers, thus providing Northern with distribution volume
that is  stable  from  year to  year.  NEDL  serves  approximately  1.5  million
customers in Northern's  area and charges its customers  access fees for the use
of the distribution system.

At December 31, 2000,  Northern's  electricity  distribution  network (excluding
service  connections to consumers) included  approximately  17,000 kilometers of
overhead  lines and  approximately  27,000  kilometers  of  underground  cables.
Substantially all substations are owned in freehold, and most of the balance are
held on  leases  which  will not  expire  within 10 years.  In  addition  to the
circuits  referred to above,  Northern's  distribution  facilities  also include
approximately 26,000 transformers and approximately 25,000 substations.

Northern  Electric Supply Limited ("NESL") focuses on Northern's supply business
and is responsible for marketing, tariff setting, contracts and customer service
in connection  with the supply of both  electricity and gas.  Northern's  supply
business  involves the bulk purchase of  electricity  and gas and the subsequent
sale to individual customers.  The purchase of electricity is primarily from the
Pool.

Under the terms of its PES license,  Northern currently  supplies  approximately
1.04  million  supply  customers  within its  authorized  area.  In  addition to
competing for supply customers in its authorized  area,  Northern holds a second
tier license to compete with the RECs and other suppliers to supply  electricity
to customers outside its authorized area.  Northern supplies customers in all 15
PES areas in Great Britain and Northern Ireland.

               Total Electric Sales of Northern By Customer Class

                                                2000           1999        1998

Residential                                     22.7%          27.5%       32.4%
Small General Service                           12.0           12.7        16.2
Large General Service                           64.2           58.1        49.9
Sales for Resale and Other                       1.1            1.7         1.5
                                               ------        ------        -----
TOTAL                                          100.0%         100.0%      100.0%
                                               ======        =======      ======

Northern  Electric & Gas Ltd.  ("NEAGL"),  a wholly owned subsidiary of Northern
Electric plc,  holds a Gas Suppliers'  License,  under which it is authorized to
supply gas  throughout  Great  Britain.  This license  includes  standard  terms
relating  to supply  obligations,  social  obligations  and other  miscellaneous
provisions dealing with metering,  rights of entry,  provision of information to
the Regulator  and  emergencies.  There are no price control  provisions in this
license.   The  gas  supply  market  is  now  fully  competitive,   having  been
progressively opened up to competition as the monopoly of the former state-owned
British Gas Corporation (which later became British Gas plc, and is now known as
Centrica) has been removed by  legislation.  Gas suppliers use the  transmission
system of BG plc (now known as Lattice) to transport gas from the point at which
it is input into the  national  transmission  system to the point at which it is
supplied to customers'  premises.  NEAGL also hold a Gas Shippers'  License that
authorizes the company to make  arrangements with gas transporters for gas to be
introduced  into,  conveyed by means of or taken out of pipeline system operated
by a gas transporter, either generally or for purposes connected with the supply
of gas to any premises  specified in the license.  As at December 31, 2000 NEAGL
had 470,000 gas customers in Great Britain.  The gas supply offered by NEAGL and
the  electricity  supply  offered by  Northern  Electric  plc are  available  to
residential customers in one form of contract know as a "dual fuel contract."

<PAGE>
                  Total Gas Sales of Northern By Customer Class

                                               2000          1999         1998

Residential                                    64.2%         70.0%        45.5%
Commercial                                     35.8          30.0         54.5
                                               -----        ------       ------
TOTAL                                         100.0%        100.0%       100.0%
                                              ======        ======       ======

Integrated  Utility Services Limited ("IUSL"),  a subsidiary of Northern,  is an
engineering  company  whose main role is to adapt and maintain the  distribution
network of NEDL and to sell related services to third parties. IUSL continues to
work in close  cooperation  with  NEDL  that  will see IUSL  concentrate  on new
connections  and  third  party  work in 2001.  IUSL has  continued  to make cost
reductions and improve  productivity during the past year by reviewing processes
with both suppliers and staff and the implementation of performance  related pay
for staff.  IUSL has pioneered  techniques using innovative  diagnostic  testing
equipment  that reduces the need for  intrusive  maintenance.  The equipment can
identify some of the causes of potential  systems  failures before breakdown and
subsequent  loss of supply  occurs.  IUSL  continues  to develop its third party
customer base with  significant  contracts  with other  electrical  distribution
infrastructure owners.

Northern  Electric  Generation  Limited  ("Northern  Generation"),   a  Northern
subsidiary,  focuses on electricity generation,  primarily through its ownership
in  Teesside  (described  below)  and its  operation  and  ownership  of  Viking
(described  below).  Northern  Generation  also owns and  operates a 5 MW diesel
power  generating  plant  located  in  Northallerton,  England,  and  has  a 75%
ownership in a 1.8 MW windfarm located at Kirkheaton, Northumberland.

Teesside.  Teesside Power Limited ("Teesside") owns and operates an 1,875 net MW
combined cycle gas-fired  power plant at Wilton.  Northern owns a 15.4% interest
in  Teesside,  but does not  operate  the plant.  Northern  purchases  400 MW of
electricity  from Teesside under a long-term  power purchase  agreement which is
contracted until March 31, 2008.

Viking.  Northern  owns 50% of this 50MW gas fired mid merit power plant located
on Teesside.  The plant is currently in the commissioning  stage, however due to
combustor  issues it is unlikely to pass the performance  criteria  required for
handover until early 2002. NEGL is being held  financially  whole by the turnkey
contractor  (Rolls  Royce)  until the plant is fit for purpose at which time the
plant will be  operated  by NEGL.  The plant will be used as part of  Northern's
strategy to hedge the purchases and sales of electricity and gas,  together with
obtaining the benefits of avoided charges together with sales premiums.

The Company,  through Northern Generation,  is pursuing a number of wind powered
generation  opportunities  both  onshore and  offshore  in the U.K.  and is also
evaluating a proposed 150 MW combined heat and power  project under  development
in Southern  England  with an  industrial  host.  This  project has been granted
section 14 approval  which is  required  to be able to burn gas.  Section 14 has
previously been the sanction,  for non-approval,  used by the U.K. government to
restrict the development of gas-fired plants in the U.K.

Northern Electric Retail Limited ("Northern  Retail"), a subsidiary of Northern,
sells electrical and gas appliances and provides account collection and customer
services for Northern's other businesses.

Northern  Metering  Services  Limited  ("Northern  Metering"),  a subsidiary  of
Northern, provides meter supply,  installation,  refurbishment and certification
services as well as meter operator and data collection services.

<PAGE>
Producing Gas Field Operations and Fields in Development

CalEnergy  Gas  (Holdings)  Limited.  CalEnergy Gas  (Holdings)  Limited and its
subsidiaries  ("CE Gas") 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. CE Gas holds various interests
in the  southern  basin of the  United  Kingdom  sector  of the  North  Sea,  as
described  below.  Also as is more fully  discussed  below, CE Gas has also 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.

<TABLE>
<S>                              <C>                    <C>                  <C>              <C>
Producing Gas Fields             Share of Remaining     Current %            Commenced        Location
                                 Reserves BCF(1)        Working Interest     Production
Anglia                           45.5 to 65.9           55.000%               11/1991         U.K. Offshore (North Sea)
Windermere                        6.8                   20.000%                4/1997         U.K. Offshore (North Sea)
Victor                            9.0                    5.000%                9/1984         U.K. Offshore (North Sea)
Schooner                         15.7                    4.820%               10/1996         U.K. Offshore (North Sea)
Johnston                         27.1                   22.113%               10/1994         U.K. Offshore (North Sea)

Fields in Development            Size Km2
Pila Area Concession             12,639(2)              100.000%                              N.W. Poland (Polish Trough)
EP389                            10,000                  40.789%                              S.W. Australia Onshore (Perth Basin)
Yolla Discovery                     550                  20.000%                              S.E. Australia Offshore (Bass Basin)
Otway Basin                         775                  25.000%                              S.E. Australia Offshore (Otway Basin)

</TABLE>
(1)Gas  reserves  in Billion  cubic  feet (or "Bcf") as of January 1, 2001.  The
classification  "Remaining"  means  reserves which  geophysical,  geological and
engineering  data  indicate to be in place or  recoverable  (as the case may be)
with a 50% probability the reserves will exceed the estimate.
(2)Subject to 25% relinquishment of the original area after years 2, 6, 8 and 10
during the 10 year contract term based on work program results.

Producing Fields

Anglia  Field:  The Anglia  Field is located in the central part of the Southern
North Sea, approximately 36 miles north of Bacton on the UK coast. CalEnergy Gas
has a 55% working  interest in this field.  Remaining  reserves as at January 1,
2001 are 45.5 to 65.9 Bcf net to CalEnergy  Gas.  The field is produced  from an
unmanned  platform  (Anglia A) with six production  wells and a two-well  subsea
tieback  (Anglia B). Anglia B is located three miles to the west of Anglia A and
is connected by a single 8" pipeline.  Production is exported via a 16-mile, 12"
pipeline to the  Conoco-operated  Lincolnshire  Offshore  Gas  Gathering  System
(LOGGS) where gas and liquids are separated and  transported  via a 36" pipeline
to the  Theddlethorpe  gas terminal on the coast. The Anglia field's average net
production for the year 2000 was 22.3 MMscf/d  (million  standard cubic feet per
day).  CalEnergy  Gas sells its share of Anglia gas to its  affiliate,  Northern
Electric and Gas Limited, and to Innogy plc.

<PAGE>
Windermere  Field:  The  Windermere  Field is located in the eastern part of the
Southern North Sea, approximately 62 miles east of Hull on the UK coast, and has
remaining  reserves as at January 1, 2001 of 6.8 Bcf net to  CalEnergy  Gas. The
field  is  produced  by an  unmanned  platform  that has two  wells.  The gas is
transported  via a  single  8"  pipeline  to  the  Markham  Field,  where  it is
compressed and  redelivered  through the K13  pipeline  system to the Den Helder
terminal on the Netherlands coast. CalEnergy Gas holds a 20% working interest in
this field. The Windermere  Field's average net production for the year 2000 was
5.3 MMscf/d. Gas is sold to N.V. Nederland's Gasunie.

Victor  Field:  The  Victor  Gas Field is  located  in the  central  part of the
Southern North Sea,  approximately 80 miles east of the  Theddlethorpe  terminal
and has  remaining  reserves  as at January 1, 2001 of 9.0 Bcf net to  CalEnergy
Gas.  An  unmanned  platform  is  installed  and the  field  produces  from five
production  wells and a sixth subsea well tied back to the platform.  The gas is
exported  through a 16"  pipeline  to the Viking  Field and then  onwards to the
Theddlethorpe  gas terminal.  The Victor Field's  average net production for the
year  2000 was 4.7  MMscf/d.  Gas is sold to  British  Gas  Trading  Limited,  a
subsidiary of Centrica. CalEnergy Gas holds a 5% working interest in this field.

Schooner  Field:  The  Schooner  Field is  located in the  northern  part of the
Southern North Sea and has remaining  reserves as at January 1, 2001 of 15.7 Bcf
net to CalEnergy Gas. The field is produced by an unmanned platform that is tied
back through a 17.5-mile,  16" flow line to the Murdoch platform.  Production is
achieved from seven wells.  The gas is transported  through the Caister  Murdoch
System (CMS) pipeline to the Theddlethorpe  gas terminal.  CalEnergy Gas holds a
4.82% working  interest in the Schooner Field.  The Schooner Field's average net
production  for the year 2000 was 2.0 MMscf/d.  CalEnergy Gas sells its share of
Schooner gas to its affiliate Northern Electric and Gas Limited.

Johnston  Field:  The Johnston  Gas Field is located in the  Southern  North Sea
approximately  56 miles  north  east of  Scarborough  on the UK  coast,  and has
remaining  reserves as at January 1, 2001 of 27.1 Bcf net to CalEnergy  Gas. The
field is produced  from three  subsea  wells tied back to the  Ravenspurn  North
field via a 4.5-mile, 12" pipeline. Gas is exported via the Cleeton Field to the
Dimlington  terminal via a 33 mile, 36" pipeline.  The field is unitized between
Blocks  43/26a and 43/27a.  CalEnergy  Gas derives  its  interest  through a 30%
working  interest in Block 43/27a.  The Johnston  Field's average net production
for the year  2000 was 53  MMscf/d.  Gas is sold to TXU  Europe  Energy  Trading
Limited.  In 1999,  as a result of a revision  to the Unit Area,  CalEnergy  Gas
increased it working  interest in the field from  18.264% to 22.113%.  CalEnergy
Gas' share of production in 2000 was 16.0 MMscf/d.

Projects in Development

Pila   Concession.   Poland's  energy  market  is  currently   undergoing  major
adjustments as it moves from a centrally planned to an open, commercially driven
free market.  During this  process,  CalEnergy Gas believes that there will be a
number of gas opportunities  created.  CalEnergy Gas' current interest in Poland
is centered on the Pila Concession,  acquired by CalEnergy Gas (Polska) Sp z o.o
in 1998.

The Pila  Concession,  valid for a period of 30 years  for the  exploration  and
exploitation of hydrocarbons, was effective from April 23, 1998 and is currently
in the  exploration  phase with a drilling  program that  commenced in September
2000. The original concession,  covering an area of 12,639 km2 in the north west
of Poland,  sits within the Permian  Basin of north west Europe which  stretches
from the UK sector of the Southern North Sea across the  Netherlands and Germany
into Poland.

The prospects  CalEnergy has identified to date has  encouraged  both POGC (10%)
and  Petrobaltic  (10%) to join  CalEnergy  Gas (80%) in the  drilling  phase of
exploration activity.

<PAGE>
EP 389. The Perth Basin,  situated onshore and offshore the south west corner of
Australia,  contains a sequence of up to 15,000  meters of Permian to Cretaceous
sediments.  To date,  exploration  in the Perth  Basin has  concentrated  on the
onshore,   with   several   hydrocarbon   fields   being   discovered   in   the
central--northern portion of the basin.

Since August 1997,  CalEnergy Gas (UK) Limited has had a 40.789% equity interest
in permit EP389.  At the same time,  CalEnergy Gas joined Empire in applications
for four  other  permits  that were  subsequently  awarded,  such that the joint
venture's portfolio of five permits now covers approximately 10,000 km2.

EP389  has  recently  entered  a  new  five-year  permit  period  following  the
relinquishment  of  approximately  650 km2.  The joint  venture is  planning  to
commence exploratory drilling before the end of 2001.

Yolla.  CalEnergy  Gas owns  interests  in  three  licenses  in the Bass  Basin,
including a 20%  interest  in the Yolla gas field.  Currently  undeveloped,  the
Yolla gas field is  commercially  viable and is planned to be  developed  in the
near future.  Situated between  Victoria and Tasmania in the Bass Straight,  the
field is  positioned to supply gas to Victoria,  where a gas supply  shortage is
predicted  in the coming  years.  Preliminary  engineering  and design have been
completed, and commercial opportunities for Yolla are being reviewed.

The Yolla gas field contains  recoverable  reserves of approximately 400 Bcf and
30 million barrels of petroleum  liquids in the main reservoir,  with additional
reserves possible in other unexplored parts of the field.

Otway  Basin.  Just 40 km from the  major  gas  markets  of  Victoria  lies some
promising exploration acreage in the Offshore Otway Basin.  CalEnergy Gas owns a
25% interest in the Vic/P43  license,  acquired in 1999. In 2000,  CalEnergy Gas
and their joint venture partners  acquired 775 km2 of 3D seismic in this permit.
The two  identified  structures in Vic/P43 are thought to contain up to 1 Tcf of
gas.

<PAGE>
CalEnergy Generation

The following  tables set out certain  information  concerning  various  Company
independent power projects in operation and under construction.

<TABLE>
<CAPTION>
<S>                           <C>        <C>        <C>         <C>             <C>           <C>         <C>           <C>
---------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Project(1)                    Facility   Net MW     Fuel        Location        Commercial    U.S. $      Power         Political
                              Net MW     Owned(2)                               Operation     Payments    Purchaser(3)  Risk
                                                                                                                        Insurance
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Projects in Operation
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Salton Sea I                         10          5  Geo         California          1987      Yes         Edison        No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Salton Sea II                        20         10  Geo         California          1990      Yes         Edison        No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Salton Sea III                       50         25  Geo         California          1989      Yes         Edison        No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Salton Sea IV                        40         20  Geo         California          1996      Yes         Edison        No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Salton Sea V                         49         25  Geo         California          2000      Yes         Market/Zinc   No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Vulcan                               34         17  Geo         California          1986      Yes         Edison        No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Elmore                               38         19  Geo         California          1989      Yes         Edison        No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Leathers                             38         19  Geo         California          1990      Yes         Edison        No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Del Ranch                            38         19  Geo         California          1989      Yes         Edison        No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
CE Turbo                             10          5  Geo         California          2000      Yes         Market/Zinc   No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Saranac                             240         90  Gas         New York            1994      Yes         NYSEG         No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Power Resources                     200        100  Gas         Texas               1988      Yes         TUEC          No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Yuma                                 50         25  Gas         Arizona             1994      Yes         SDG&E         No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Roosevelt Hot Springs                23         17  Geo         Utah                1984      Yes         UP&L          No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Desert Peak                          10         10  Geo         Nevada              1985      Yes         N/A           No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Mahanagdong                         165        149  Geo         Philippines         1997      Yes         PNOC-EDC GOP  Yes
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Malitbog                            216        216  Geo         Philippines       1996-97     Yes         PNOC-EDC GOP  Yes
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Upper Mahiao                        119        119  Geo         Philippines         1996      Yes         PNOC-EDC GOP  Yes
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Total Projects in Operation       1,350        890
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------

----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Projects Under Construction
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------

----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Casecnan                            150        105  Hydro       Philippines         2001      Yes         NIA GOP       Yes
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Cordova                             537        537  Gas         Illinois            2001      Yes         ElPaso/MEC    No
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------

----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Total Projects Under
Construction                        687        642
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------

----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Total Power Generation
Projects                          2,037      1,532
----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
</TABLE>
(1)The Company operates all such projects other than Desert Peak.
(2) 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.
(3)PNOC-Energy   Development   Corporation   ("PNOC-EDC");   Government  of  the
Philippines ("GOP") and Philippine National  Irrigation  Administration  ("NIA")
(NIA also purchases water from this facility). The Government of the Philippines
undertaking  supports  PNOC-EDC's  and NIA's  respective  obligations.  Southern
California Edison Company ("Edison"); San Diego Gas & Electric Company ("SDG&E);
Utah Power & Light Company ("UP&L");  Bonneville Power  Administration  ("BPA");
New York State Electric & Gas Corporation  ("NYSEG");  Texas Utilities  Electric
Company  ("TUEC");  Zinc Recovery Project ("Zinc");  El Paso Energy  Corporation
("El Paso") and MidAmerican Energy Company ("MEC").

<PAGE>

Projects in Operation

CE Generation Geothermal Facilities

CE  Generation  LLC ("CE  Generation"),  a 50% owned  subsidiary of the Company,
affiliates  currently  operate ten geothermal  plants in the Imperial  Valley in
California  (the "Imperial  Valley  Projects").  Five of these  Imperial  Valley
Project plants (the  "Partnership  Projects")  consist of the Vulcan,  Hoch (Del
Ranch),  Turbo,  Elmore and Leathers  projects (the "Vulcan  Project," the "Hoch
(Del  Ranch)  Project,"  the  "Turbo  Project",  the  "Elmore  Project"  and the
"Leathers Project," respectively).  The remaining five operating Imperial Valley
Project plants (the "Salton Sea Projects") consist of Salton Sea I, II, III, IV,
and V projects  (the  "Salton Sea I Project"  the  "Salton  Sea II Project,  the
"Salton Sea III  Project",  the "Salton Sea IV  Project",  and the "Salton Sea V
Project", respectively).

The Vulcan Project, Hoch (Del Ranch) Project, Elmore Project,  Leathers Project,
Salton  Sea II  Project  and the  Salton Sea III  Project  sell  electricity  to
Southern California Edison Company ("Edison") under 30-year Standard Offer No. 4
Agreements ("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
as-available  capacity  price is based on a payment  schedule as approved by the
CPUC from time to time. The contract  energy payment was fixed for the first ten
years.  The fixed price  periods for the Vulcan,  Del Ranch,  Elmore,  Leathers,
Salton Sea II and Salton Sea III  Projects  expired in  February  1996,  January
1999, December 1998, December 1999, April 2000, and February 1999, respectively.
Thereafter, the energy payments are based on Edison's Avoided Cost of Energy.

The Salton Sea I Project  and Salton Sea IV Project  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.  Approximately 56% of the
kWhs are sold under the Salton Sea IV Power Purchase Agreement at a fixed energy
price,  which is  subject  to  quarterly  adjustment  by  reference  to  various
inflation-related  indices,  through June 20, 2017 (and at Edison's avoided cost
of energy thereafter), which the remaining 44% of the Salton Sea IV Project kWhs
are sold according to a 10-year fixed price schedule  followed by payments based
on a modified  avoided cost of energy for the succeeding 5 years and at Edison's
avoided cost of energy thereafter.

The Salton Sea V Project began  operations  in 2000 and will sell  approximately
one-third of its net output to the Zinc Recovery Project. The remainder is being
sold through other market transactions.

The net output of the Turbo  Project is being sold through  market  transactions
but may be sold to the Zinc Recovery Project when completed.

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.  Based  on  public  announcements,  the  Company
understands  that Edison has not made  payments to other  qualifying  facilities
("QFs") from which Edison purchases power and has not made scheduled payments of
debt service.  Edison's  senior  unsecured debt  obligations are currently rated
Caa2 (on watch for possible downgrade) by Moody's and by S&P.

The  Company is aware that there have been  public  announcements  that  Edison,
other  industry  participants  and  governmental  entities have taken actions in
response to Edison's financial condition. These actions include the following:

<PAGE>
o        The Federal Energy Regulatory  Commission  ("FERC") has issued an order
         eliminating  requirements  that Edison and other  California  utilities
         purchase power from the structured  power market in California in order
         to provide them with an  opportunity  to obtain power from  alternative
         sources at a lower cost.

o        The State of  California  has  enacted  legislation  to provide for the
         California  Department of Water  Resources to purchase  wholesale power
         and sell it to retain customers, which will be funded by a surcharge on
         retail rates.  The  California  legislature is also  considering  other
         legislation  to  improve  the  financial  condition  of the  California
         electric utilities.

o        The California Public Utilities Commission ("CPUC") approved a decision
         on March 27, 2001 to increase retail electricity rates by approximately
         40%. In another  decision that day, the CPUC ordered  Edison to pay QFs
         on a go forward  basis  within 15 days of the invoice  and  purportedly
         modified the calculation of Short Run Avoided Cost.

o        The  State of  California  and  Edison  have  announced  a  preliminary
         agreement for the State to purchase  Edison's  transmission  assets for
         $2.7  billion  and to allow  Edison to issue  bonds  for a  substantial
         portion of its under collection or revenues.

The Company can give no assurance as to the likely  result of any of the actions
described above or as to whether such actions will have a positive effect on the
financial  condition of Edison or its  willingness  to make  payments  under the
Power Purchase Agreements.

Edison  has  failed  to pay  approximately  $76  million  due  to CE  Generation
affiliates  under the Power Purchase  Agreements for power delivered in November
and  December  2000 and January  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 and March 2001. Edison has not notified
the Company as to when it can expect to receive these  payments.  This continued
non-payment  by Edison could result in an untenable  situation for the continued
operation of the Imperial Valley Projects unless  additional  funds are obtained
in the near future.

On February  21, 2001,  the Imperial  Valley  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 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'  Motion for Summary  Adjudication  and a Declaratory  Judgment
ordering  that:  1) under the Power  Purchase  Agreements,  the Imperial  Valley
Projects have the right to temporarily suspend deliveries of capacity and energy
to Edison, 2) the Imperial Valley 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.  The Imperial  Valley  Projects  intend to vigorously
pursue  its  other  remedies  in this  action  in light of  Edison's  continuing
non-payment.

The Company is hopeful that the current  Edison  situation is temporary  and the
proceedings in the legal,  regulatory,  financial and political arenas will lead
to the  improvement of Edison's  financial  condition in the near future and the
payment by Edison of amounts due under the Power Purchase  Agreements.  However,
no assurance can be given that this will be the case.

As a result  of  Edison's  failure  to make the  payments  due  under  the Power
Purchase  Agreements  and the recent  downgrades  of  Edison's  credit  ratings,
Moody's has  downgraded  the ratings  for the Salton Sea Funding  Corp.  project
related debt to Caa2  (negative  outlook) and S&P has downgraded the ratings for
the  project  related  debt to BBB- and has placed the project  related  debt on
"credit watch negative".  Accordingly,  the Funding Corporation does not believe
it is currently able to obtain funds in the banking or capital markets. However,
a  failure  by Edison  to make  these  payments  as well as  subsequent  monthly
payments,  for a  substantial  period of time after the payments are due, is not
expected to have a material adverse effect on the ability of the Company to make
payments on its debt obligations. However, there can be no assurance that such a
failure by Edison would not cause a material adverse effect.

<PAGE>
CE Generation Gas Facilities

CE Generation affiliates currently operate the Saranac, Power Resources and Yuma
natural gas plants (the "Saranac  Project",  "Power Resources Project" and "Yuma
Project",  respectively). The Saranac Project, Power Resources Project, and Yuma
Project are collectively referred to as the "Gas Plants".

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  ("SDG&E") under an existing  30-year power purchase  contract
("Yuma PPA"). The project entity,  Yuma  Cogeneration  Associates  ("YCA"),  has
executed steam sales contracts with an adjacent  industrial entity to act as its
thermal host.  Since the industrial  entity has the right under its agreement to
terminate  the agreement  upon one year's  notice if a change in its  technology
eliminates its need for steam, and in any case to terminate the agreement at any
time upon three years  notice,  there can be no assurance  that the Yuma Project
will  maintain  its status as a  qualifying  facility  ("QF").  However,  if the
industrial entity terminates the agreement, YCA anticipates that it will be able
to locate an alternative thermal host in order to maintain its status as a QF.

SDG&E, a wholly-owned subsidiary of Sempra Energy, is a public utility primarily
engaged in the business of supplying  electric energy and natural gas service in
San Diego County and southern Orange County in California.  The Company is aware
that there have been public  announcements that SDG&E's financial  condition has
deteriorated  as a result of reduced  liquidity.  SDG&E has been  current in its
payments to the Yuma Project for electricity generated. SDG&E's senior unsecured
debt obligations are currently rated Aa3 by Moody's and AA- by S&P.

The Company is hopeful that the current  SDG&E  situation  is temporary  and the
proceedings in the legal,  regulatory,  financial and political arenas will lead
to the improvement of SDG&E's financial  condition in the near future.  However,
no assurance can be given that this will be the case.

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  (the "Saranac  PPA") with New
York State Electric & Gas ("NYSEG"). The Saranac Project is a QF and has entered
into 15-year steam purchase agreements (the "Saranac Steam Purchase Agreements")
with Georgia-Pacific Corporation and Tenneco Packaging, Inc. The Saranac Project
has a 15-year natural gas supply  contract (the "Saranac Gas Supply  Agreement")
with  Shell  Canada  Limited  ("Shell  Canada")  to supply  100% of the  Saranac
Project's  fuel  requirements.  Shell Canada is  responsible  for production and
delivery of natural gas to the U.S.-Canadian border; the gas is then transported
by the North Country Gas Pipeline Corporation ("NCGP") the remaining 22 miles to
the plant.  NCGP is a wholly-owned  subsidiary of Saranac Power  Partners,  L.P.
(the  "Saranac  Partnership"),  which also owns the Saranac  Project.  NCGP also
transports  gas for NYSEG and  Georgia-Pacific.  Each of the  Saranac  PPA,  the
Saranac Steam Purchase  Agreements and the Saranac Gas Supply Agreement contains
rates that are fixed for the respective  contract terms.  Revenues escalate at a
higher rate than fuel costs.  The Saranac  Partnership  is  indirectly  owned by
subsidiaries of CE Generation,  Tomen Corporation ("Tomen") and General Electric
Capital Corporation ("GECC").

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  (the  "Power  Resources  PPA")  with  Texas
Utilities Electric Company.  The Power Resources Project is a QF and the project
entity,  Power Resources Ltd.  ("Power  Resources"),  has entered into a 15-year
steam purchase  agreement (the "Power Resources Steam Purchase  Agreement") with
Fina Oil and  Chemical  Company  ("Fina"),  a subsidiary  of  Petrofina  S.A. of
Belgium. Power Resources has entered into an agreement (the "CE Texas Gas Supply
Agreement")  with CE Texas Gas L.P. ("CE Texas Gas") for Power  Resources'  fuel
requirements through December 2003. In June 1995, CE Texas Gas and Louis Dreyfus
Natural  Gas  Corp.  ("Dreyfus")  executed  an  eight-year  natural  gas  supply
agreement (the "CE Texas Gas-Dreyfus Gas Supply Agreement"), with which CE Texas
Gas will fulfill its supply  commitment to Power  Resources from October 1995 to
the end of the term of the Power Resources PPA. Each of the Power Resources PPA,
the Power  Resources Steam Purchase  Agreement and the CE Texas  Gas-Dreyfus Gas
Supply  Agreement  contains  rates  that are fixed for the  respective  contract
terms. Revenues escalate at a higher rate than fuel costs.

<PAGE>
Other U.S. Geothermal Interests

Roosevelt  Hot  Springs.  A  subsidiary  of the  Company  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
("UP&L")  located on the  Roosevelt Hot Springs  property  under a 30-year steam
sales contract. The Company obtained approximately $20.3 million of cash under a
pre-sale agreement with UP&L whereby UP&L paid in advance for the steam produced
by the steam field.  The Company must make certain  penalty  payments to UP&L if
the steam produced does not meet certain quantity and quality requirements.

Desert Peak. A subsidiary  of the Company is the owner of a 10 net MW geothermal
plant at Sparks,  Nevada. In 1998, the Company executed an agreement pursuant to
which the Desert Peak Project is leased to a third party power  producer and the
Company receives rental payments.

The Philippines Power Generation

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

Under the terms of an energy conversion agreement, executed on September 6, 1993
(the "Upper  Mahiao  ECA"),  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
("PNOC-EDC") at no cost.

The Upper Mahiao  Project is located on land provided by PNOC-EDC at no cost. It
takes  geothermal  steam and fluid,  also  provided by PNOC-EDC at no cost,  and
converts  its  thermal  energy  into  electrical  energy  sold to  PNOC-EDC on a
"take-or-pay" basis. Specifically,  PNOC-EDC is obligated to pay for 100% of the
electric  capacity  that is  nominated  each  year by CE Cebu,  irrespective  of
whether  PNOC-EDC  is  willing  or able to  accept  delivery  of such  capacity.
PNOC-EDC pays to CE Cebu a fee (the "Capacity  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 (the "Energy Fee") based
on the electricity  actually  delivered to PNOC-EDC  (approximately  5% of total
contract revenues).  Payments under the Upper Mahiao ECA 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.  Significant portions of
the  Capacity Fee and Energy Fee are indexed to U.S.  and  Philippine  inflation
rates, respectively.  PNOC-EDC's payment requirements, and its other obligations
under the Upper Mahiao ECA, are supported by the  Government of the  Philippines
through a performance undertaking.

The payment of the Capacity  Fee is not excused if PNOC-EDC  fails to deliver or
remove the steam or fluids or fails to provide the transmission facilities, even
if its failure was caused by a force majeure event (e.g., war,  nationalization,
etc.).  In addition,  PNOC-EDC  must  continue to make  Capacity Fee payments if
there is a force  majeure  event that affects the  operation of the Upper Mahiao
Project and that is within the reasonable  control of PNOC-EDC or the Government
of the Philippines or any agency or authority thereof.

PNOC-EDC  is  obligated  to purchase CE Cebu's  interest in the  facility  under
certain circumstances, including (i) extended outages resulting from the failure
of PNOC-EDC to provide the required  geothermal  fluid,  (ii)  certain  material
changes in policies  or laws which  adversely  affect CE Cebu's  interest in the
project,  (iii)  transmission  failure,  (iv) failure of PNOC-EDC to make timely
payments  of  amounts  due under the Upper  Mahiao  ECA,  (v)  privatization  of
PNOC-EDC  or NPC,  and (vi)  certain  other  events.  The price  will be the net
present  value  (at a  discount  rate  based  on the last  published  Commercial
Interest  Reference  Rate  of the  Organization  for  Economic  Cooperation  and
Development) of the total  remaining  amount of Capacity Fees over the remaining
term of the Upper Mahiao ECA.

<PAGE>
Mahanagdong.  The Mahanagdong  Project is a 165 net MW geothermal  power project
owned and operated by CE Luzon  Geothermal Power Company,  Inc. ("CE Luzon"),  a
Philippine  corporation of which 100% of the common stock is indirectly owned by
the Company. Another industrial company owns an approximate 10% preferred equity
interest  in the  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 NPC for distribution to the island of
Luzon.

The terms of an energy conversion agreement, executed on September 18, 1993 (the
"Mahanagdong ECA"), are substantially  similar to those of the Upper Mahiao ECA.
The Mahanagdong ECA 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  ECA are supported by the
Government 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.

Malitbog.  The Malitbog  Project is a 216 net MW  geothermal  project  owned and
operated by Visayas  Geothermal  Power Company  ("VGPC"),  a Philippine  general
partnership that is wholly owned, indirectly, by the Company. 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 is selling  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 NPC.

The  Malitbog  Project is located on land  provided by PNOC-EDC at no cost.  The
electrical  energy  produced  by the  facility  will be sold  to  PNOC-EDC  on a
take-or-pay  basis.  Specifically,  PNOC-EDC is obligated to make  payments (the
"Capacity  Payments") to VGPC based upon the available  capacity of the Malitbog
Project.  The Capacity Payments equal approximately 100% of total revenues.  The
Capacity  Payments will be payable so long as the Malitbog  Project is available
to produce  electricity,  even if the Malitbog  Project is not  operating due to
scheduled  maintenance,  because  PNOC-EDC fails to supply steam to the Malitbog
Project as required or because NPC is unable (or  unwilling) to accept  delivery
of electricity from the Malitbog Project. In addition, PNOC-EDC must continue to
make the  Capacity  Payments  if  there is a force  majeure  event  (e.g.,  war,
nationalization,  etc.) that affects the  operation of the Malitbog  Project and
that is within the  reasonable  control of  PNOC-EDC  or the  Government  of the
Philippines or any agency or authority  thereof.  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  ECA from 10% of  VGPC's  revenues  in the  early  years of the
Cooperation  Period (as defined  below) 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  (the
"Performance  Undertaking"),  which provides that all of PNOC-EDC's  obligations
pursuant  to the  Malitbog  ECA carry  the full  faith and  credit  of,  and are
affirmed and guaranteed by, the Government of the Philippines.

PNOC-EDC is obligated to purchase  VGPC's interest in the facility under certain
circumstances,  including (i) certain material changes in policies or laws which
adversely affect VGPC's interest in the project, (ii) any event of force majeure
which delays  performance  by more than 90 days and (iii)  certain other events.
The price will be the net present  value of the capital cost  recovery fees that
would have been due for the remainder of the Cooperation  Period with respect to
such generating unit(s).

<PAGE>
VGPC and  PNOC-EDC  have been  negotiating  with  respect  to  certain  disputes
concerning the Malitbog 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 intends to vigorously pursue its claims in this proceeding.

The  Malitbog  ECA  cooperation  period  will expire ten years after the date of
commencement of commercial operation of Unit III (the "Cooperation  Period"). At
the end of the Cooperation  Period, the facility will be transferred to PNOC-EDC
at no  cost,  on an "as is"  basis.  All of  PNOC-EDC's  obligations  under  the
Malitbog  ECA are  supported  by the  Government  of the  Philippines  through a
performance undertaking.

Projects in Construction

United States

Cordova. Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company,  financed and commenced  construction of a 537 MW gas
fired combined  cycle  merchant power plant to be located  northeast of the Quad
Cities in Cordova,  Illinois (the  "Cordova  Project").  The Cordova  Project is
being constructed by Stone & Webster Engineering  Corporation  ("SWEC") pursuant
to  a  date  certain,   fixed  price,  turnkey   engineering,   procurement  and
construction contract.  Cordova is scheduled to commence commercial operation in
mid-2001.

Cordova  Energy has entered into a power sales  agreement with a unit of El Paso
Energy  Corporation ("El Paso").  Under the power sales agreement,  El Paso will
purchase all the capacity and energy from the project  until  December 31, 2019.
However,  Cordova Energy has the option to elect on an annual basis to retain up
to 50% of the project  capacity and energy for sales to others.  Cordova  Energy
has  exercised  this  option for the full 50% for the first  three years and has
entered  into a power  sales  agreement  to sell  this  capacity  and  energy to
MidAmerican Energy.

SWEC's  parent,  Stone & Webster,  Incorporated,  voluntarily  filed  Chapter 11
bankruptcy on September 2, 2000 and has sold  substantially all of its assets to
Shaw Group,  Inc. Shaw Group,  Inc. has agreed to complete  substantially all of
Stone &  Webster's  contracts  for  current and future  projects  including  the
Cordova  Project.  The Company  does not believe this  situation  will cause any
material  adverse effect on the final  completion of the Cordova  Project or the
Company.

Zinc  Recovery  Project.  The  Company  developed  and  owns  the  rights  to  a
proprietary  process for the extraction of minerals from elements in solution in
the geothermal  brine and fluids  utilized at its Imperial Valley plants as well
as the production of power to be used in the extraction  process.  A pilot plant
has  successfully  produced  commercial  quality zinc at the Company's  Imperial
Valley Project.

CalEnergy Minerals LLC ("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  will be
installed near Imperial Valley Project 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 mid-2001. In
September  1999,  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.

<PAGE>
The  Zinc  Recovery   Project  is  being   constructed  by  Kvaerner  U.S.  Inc.
("Kvaerner")  pursuant  to a date  certain,  fixed-price,  turnkey  engineering,
procurement  and   construction   contract  (the  "Zinc  Recovery   Project  EPC
Contract").  Kvaerner is a wholly-owned  indirect subsidiary of Kvaerner ASA, an
international  engineering  and  construction  firm  experienced  in the metals,
mining and processing industries. The payment obligations of Kvaerner, including
payment of  liquidated  damages of up to 20% of the  contract  price for certain
delays or failures to meet  performance  guarantees,  are secured by a letter of
credit issued by Union Europeenne de CIC (or another financial institution rated
"A" or better by S&P or "A2" or better by Moody's and  otherwise  acceptable  to
Minerals LLC) in an initial aggregate amount equal to $29.6 million.

Salton Sea  Minerals  Extraction.  In  addition  to zinc  recovery,  the Company
intends to sequentially  develop manganese,  silver,  gold, lead, boron, lithium
and  other  products  as it  further  develops  the  extraction  technology.  If
successfully  developed for the other products,  the mineral  extraction process
will  provide an  environmentally  responsible  and low cost  minerals  recovery
methodology.  The Company is also investigating producing silica from the solids
precipitated out of the geothermal power process. Silica is used as a filler for
such products as paint, plastics and high temperature cement.

Philippines

Casecnan. CE Casecnan Water and Energy Company,  Inc., a Philippine  corporation
("CE  Casecnan")  which is expected to be at least 70%  indirectly  owned by the
Company, was formed in September of 1994 solely to develop,  construct,  own and
operate  the  Casecnan  Project,  a  multi-purpose  irrigation  and  150  net MW
hydroelectric  power generation project (the "Casecnan  Project") located on the
island  of  Luzon in the  Republic  of the  Philippines.  The  Casecnan  Project
consists generally of diversion  structures in the Casecnan and Taan Rivers that
will  capture and divert  excess  water in the  Casecnan  watershed  by means of
concrete, in-stream diversion weirs and transfer that water through a transbasin
tunnel of approximately 23 kilometers  (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  will allow
electrical  energy  to be  generated  at a new 150 net MW rated  capacity  power
plant, which is being constructed in an underground powerhouse cavern located at
the end of the water tunnel. A tailrace discharge tunnel of approximately  three
kilometers  will deliver  water from the water tunnel and the new  powerhouse to
the  Pantabangan  Reservoir,  providing  additional  water  for  irrigation  and
increasing  the  potential  electrical  generation  at two  downstream  existing
hydroelectric  facilities of the Philippine National Power Corporation  ("NPC"),
the government-owned and controlled  corporation that is the primary supplier of
electricity in the Philippines.

CE Casecnan is constructing  the Casecnan Project under the terms of the Project
Agreement  between  CE  Casecnan  and  the  National  Irrigation  Administration
("NIA").  Under the Project  Agreement,  CE Casecnan will  develop,  finance and
construct the Casecnan Project over the construction  period, and thereafter own
and operate the Casecnan Project for 20 years (the "Cooperation Period"). During
the 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 NPC, although NIA's obligations to CE Casecnan under
the Project  Agreement  are not dependent on 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
70% of CE  Casecnan's  revenues.  At the  end of  the  Cooperation  Period,  the
Casecnan  Project  will  be  transferred  to  NIA  and  NPC  for  no  additional
consideration on an "as is" basis.

<PAGE>
The Project Agreement  provides for additional  compensation to CE Casecnan upon
the occurrence of certain events,  including  increases in Philippine  taxes and
adverse   changes  in  Philippine  law.  Upon  the  occurrence  and  during  the
continuance of certain force majeure  events,  including  those  associated with
Philippines  political action,  NIA may be obligated to buy the Casecnan Project
from CE  Casecnan at a buy out price  expected to be in excess of the  aggregate
principal amount of the outstanding CE Casecnan debt  securities,  together with
accrued but unpaid interest.

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.  The Project  Agreement and
the  Performance  Undertaking  provide for the resolution of disputes by binding
arbitration in Singapore under international arbitration rules.

NIA's payments of obligations  under the Project Agreement are expected to be CE
Casecnan's  sole  source  of  operating  revenues.   Because  of  CE  Casecnan's
dependence on NIA, any material failure of NIA to fulfill its obligations  under
the  Project  Agreement  and  any  material  failure  of  the  Republic  of  the
Philippines to fulfill its obligations  under the Performance  Undertaking would
significantly  impair the ability of CE Casecnan to meet its existing and future
obligations.

CE Casecnan has entered into a fixed-price,  date certain,  turnkey engineering,
procurement  and  construction  contract to  complete  the  construction  of the
Casecnan  Project (the  "Casecnan  Construction  Contract").  The work under the
Casecnan  Construction 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 Casecnan  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 lender's 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.
Accordingly,  the Casecnan Project is now expected to become  operational by the
third quarter of 2001.  The delay in completion is  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.

The receipt of the working  schedule does not change the Guaranteed  Substantial
Completion  Date under the  Replacement  Contract,  and the  Contractor is still
contractually  obligated  either to complete the  Casecnan  Project by March 31,
2001 or to pay delay liquidated  damages.  As a result of receipt of the working
schedule,  however,  CE  Casecnan  has 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, the 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 (the
"Shareholder  Support  Letter") to cover  additional  costs  resulting  from the
Contractor's schedule delay.

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 force majeure events. In a March 20, 2001 Supplement to Request for
Arbitration, the Contractor also seeks compensation for alleged additional costs
it incurred from the claimed force majeure  events to the extent it is unable to
recover from its insurer.  CE Casecnan  believes  such  allegations  are without
merit and intends to vigorously defend the Contractor's claims.

The  Republic of the  Philippines  ("RP") has recently  experienced  a period of
political  unrest and  governmental  uncertainty  relating to the impeachment of
former  President  Estrada  which  resulted  in a change in the  Presidency  and
related changes to the RP cabinet and overall government administration.

<PAGE>
Although the  obligations  of the NIA to make  payments to CE Casecnan for water
and electricity fees under the Project Agreement with NIA and the obligations of
the  RP  under  the  related  sovereign  performance  undertaking  are in no way
dependent on  maintaining  any particular RP  administration  in place or on any
particular government's annual budgetary appropriations,  it is possible that if
the recent Philippine  governmental  uncertainty would reoccur, it could have an
adverse impact on the Casecnan  Project,  which, as noted above, is scheduled to
commence commercial operation and commence receiving payments in 2001.

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,  CE  Casecnan 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.  Although
the  transmission  line is  complete,  NIA has not yet  installed  the  Casecnan
Project's metering equipment. Accordingly, no liquidated damages payments to NIA
have been made.

CE  Casecnan'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 CE
Casecnan, including the Company, and no directors,  officers or employees of the
Company  will  guarantee  or be in any way liable for  payment of CE  Casecnan's
obligations.  As a result, payment of CE Casecnan's obligations depends upon the
availability  of  sufficient  revenues  from CE  Casecnan's  business  after the
payment of operating expenses.

HomeServices

The Company owns approximately 83% of HomeServices.Com,  Inc.  ("HomeServices"),
the second largest  residential  real estate brokerage firm in the United States
based on aggregate closed  transaction  sides in 1999 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 primarily
under the Edina Realty, Iowa Realty,  J.C. Nichols  Residential,  CBSHOME,  Paul
Semonin  Realtors,  Long Realty and Champion Realty brand names in the following
twelve states: Minnesota, Iowa, Arizona, Kansas, Missouri,  Kentucky,  Nebraska,
Wisconsin,  Indiana,  Maryland,  North  Dakota  and South  Dakota.  HomeServices
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, 2000.  HomeServices'  major markets  consist of the  following  metropolitan
areas:  Minneapolis and St. Paul, Minnesota;  Des Moines, Iowa; Omaha, Nebraska;
Kansas  City,  Kansas;  Louisville,  Kentucky;  Springfield,  Missouri;  Tucson,
Arizona and Annapolis, Maryland.

The Global Energy Market

The opportunity for independent  power  generation and energy  distribution  and
supply  is  a  global  competitive  market  as  many  countries  have  initiated
restructuring  and  privatization  policies that  encourage the  development  of
independent power generation and independent  distribution and supply of energy.
The movement toward  privatization in some developing  countries has created new
markets.  The need for economic  expansion  has caused many  countries to select
private power development as their only practical alternative and to restructure
their  legislative and regulatory  systems to facilitate such  development.  The
Company  intends to  evaluate  opportunities  in these  markets  and to develop,
construct  and acquire  power  generation,  distribution  and supply and related
energy  projects  meeting  its  strategic  criteria  both inside and outside the
United States.  In addition,  as  privatization,  deregulation and restructuring
initiatives  are  enacted in various  countries  and states,  the  Company  will
evaluate  opportunities  to acquire power  generation,  distribution  and supply
assets, as well as other energy related infrastructure assets.

<PAGE>
In  pursuing  its  strategy,   the  Company  presently  intends  to  focus  upon
development   and   acquisition    opportunities    in   countries    possessing
characteristics  that meet the Company's  general  investment  criteria.  At the
present time, the Company is active in the United States,  the  Philippines  and
the United Kingdom.  Set forth below is certain general  information  concerning
the present status of the energy markets in those countries in which the Company
currently has significant operations.

The United States

In the United States,  the independent  power industry  expanded  rapidly in the
1980s,  facilitated by the enactment of the Public Utilities Regulatory Policies
Act  ("PURPA").  PURPA was enacted to encourage the production of electricity by
non-utility companies (frequently referred to as independent power companies) as
well as to lessen  reliance on imported  fuels.  According  to the Utility  Data
Institute,  independent power producers were responsible for the installation of
approximately  30,000 MW of  capacity,  or 50%,  of the United  States  electric
generation  capacity that has been placed in service since 1988. However, as the
size of the United States independent power market increased, available domestic
power capacity and competition in the industry also significantly increased.

During the last few years,  many states began to accelerate the movement  toward
more  competition  in many  aspects  of the  electric  power  market,  including
generation,  transmission,  distribution and supply. Extensive federal and state
legislative  and  regulatory  reviews  are  presently  underway  in an effort to
further such competition.  In particular,  the state of California, in which the
Company has several power production  facilities,  adopted a bill to restructure
California's  electric  industry by providing for a phased-in  competitive power
generation industry,  with an independent system operator, and for direct access
to generation for all power  purchasers  under certain  circumstances.  The bill
provided  that  existing  qualifying  facility  power sales  agreements  will be
honored.  Approximately  one-half of the states  have  enacted  electric  choice
legislation and other states have or are expected to take similar steps aimed at
increasing  competition by restructuring the electric industry,  allowing retail
competition and  deregulating  most electric rates. In addition,  recent federal
legislation  has been proposed  which would repeal PURPA and the Public  Utility
Holding Company Act of 1935, as amended.  However,  the current energy crisis in
California has resulted in a slow down in deregulation  of the electric  utility
industry.  The power  exchange is no longer  functioning  and it is difficult to
predict  the  ramifications  of the  California  energy  crisis  on the  overall
deregulation of the electric utility industry.

Legislation to initiate retail  electric  competition was introduced in the Iowa
legislature in the 2000 session,  but it did not pass.  Deregulation  of the gas
supply function  related to small volume  customers is also being  considered by
the Iowa Utilities Board ("IUB").  MidAmerican Energy has actively  participated
in the legislative and regulatory  processes.  MidAmerican Energy cannot predict
the  timing  or  ultimate  outcome  of  any  potential  electric   restructuring
legislation or gas restructuring in Iowa.

The  introduction  of  competition  in the  wholesale  market has  resulted in a
proliferation of power marketers and a substantial  increase in market activity.
The wholesale  market has also increased in volatility.  As this market matures,
volatility may decline.

With the elimination of the energy adjustment clause in Iowa, 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.

<PAGE>
The Company  cannot  predict the final form or timing of the  proposed  industry
restructuring  or the impact on its operations.  However,  the Company  believes
that the impending  changes in the regulation of the United States power markets
will reflect  many aspects of the United  Kingdom  model  (discussed  below) for
competitive  generation,  transmission,  distribution and supply of energy.  The
Company further expects that the current effort to introduce  broader  wholesale
and retail  competition in the United States will result in a  continuation  and
acceleration of the recent trend toward  consolidation  among domestic utilities
and   independent   power   producers  and  an  increase  in  the  trend  toward
disaggregation (or unbundling) of vertically  integrated utilities into separate
generation, transmission and distribution businesses.

MidAmerican  Energy is subject to  comprehensive  regulation by several  utility
regulatory agencies that significantly  influences the operating environment and
the recoverability of costs from utility customers.  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.

Under a 1997  pricing  plan  settlement  agreement  resulting  from an IUB  rate
proceeding,  electric  prices  for  MidAmerican  Energy's  Iowa  industrial  and
commercial  customers  were  reduced  through  a retail  access  pilot  project,
negotiated  individual electric contracts and a tariffed rate reduction for some
non-contract commercial customers.

The negotiated electric contracts have differing terms and conditions as well as
prices. The vast majority of the contracts expire during the period 2003 through
2005,  although some large  customers have contracts  extending to 2008. Some of
the  contracts  have  price  renegotiation  and  early  termination   provisions
exercisable  by either  party.  Prices are set as fixed  prices;  however,  many
contract allow for potential  price  adjustments  with respect to  environmental
costs,  government imposed public purpose programs,  tax changes, and transition
costs. While the contract prices are fixed (except for the potential  adjustment
elements),  the costs MidAmerican  Energy incurs to fulfill these contracts will
vary. On an aggregate basis the annual revenues under contract are approximately
$180 million.

Under the 1997 pricing plan settlement agreement, if MidAmerican Energy's annual
Iowa electric  jurisdictional return on common equity exceeds 12%, then earnings
above the 12% level will be shared  equally  between  customers and  MidAmerican
Energy. If the return exceeds 14%, then two-thirds of MidAmerican Energy's share
of those earnings above the 14% level will be used for  accelerated  recovery of
certain  regulatory  assets.  During 2000,  MidAmerican  Energy  credited  $14.8
million to its Iowa non-contract customers related to the return calculation for
1999,  which was approved by the IUB,  subject to  additional  refund.  In 2000,
MidAmerican  Energy accrued $21.6 million for customer  credits relating to 2000
operations.  This Iowa electric  retail revenue  sharing plan remained in effect
through the year 2000.  The rates  established  by the pricing  plan  settlement
agreement  will  remain in effect  until  either the plan is  renegotiated  or a
change in rates is approved by the IUB pursuant to a rate proceeding.

On March 14, 2001,  the Office of Consumer  Advocate of the Iowa  Department  of
Justice filed a petition with the IUB to reduce MidAmerican Energy's Iowa retail
electric  rates by  approximately  $77  million  annually.  This  filing will be
contested by  MidAmerican  Energy and,  under Iowa law, the IUB must rule on the
petition within ten months from March 14, 2001. Iowa law provides that the rates
collected  after the filing of the petition are subject to refund with  interest
if they exceed rates finally approved by the IUB.

The pricing plan settlement  agreement precluded  MidAmerican Energy from filing
for increased  rates prior to January 1, 2001,  unless the return fell below 9%.
Other parties  signing the  agreement  were  prohibited  from filing for reduced
rates prior to 2001 unless the return,  after  reflecting  credits to customers,
exceeded  14%.  The  agreement  also  eliminated   MidAmerican  Energy's  energy
adjustment clause,  and, as a result, the cost of fuel is not directly passed on
to customers.

<PAGE>
In connection with the March 1999 approval by the IUB of the MidAmerican  Merger
and March 2000  affirmation as part of the Investor  Group's  acquisition of the
Company,  the Company is required,  among other things,  to use all commercially
reasonable efforts to maintain an investment grade credit rating for MidAmerican
Energy  and  its  long-term  debt  and to  seek  the  approval  of the  IUB of a
reasonable utility capital structure if MidAmerican Energy's common equity level
decreases  below  specified  levels  (42%  and  39%,   respectively,   of  total
capitalization) under certain circumstances.  MidAmerican Energy's common equity
level at December 31, 2000 was above these levels.

In December 1997, the Governor of Illinois signed into law a bill to restructure
Illinois'  electric utility industry and transition it to a competitive  market.
Under the law,  larger  non-residential  customers  in  Illinois  and 33% of the
remaining  non-residential  Illinois  customers  were  allowed  to select  their
provider of electric  supply  services  beginning  in October 1, 1999.  Starting
December 31, 2000, all other  non-residential  customers  were allowed  supplier
choice.  Residential  customers  all receive  the  opportunity  to select  their
electric supplier beginning May 1, 2002.

The law also provides for Illinois  earnings above a computed level of return on
common equity to 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 30-year  Treasury Bond rates plus a premium of
5.50%  for 1998  and 1999 and a  premium  of 8.5%  for 2000  through  2004.  The
two-year  average above which sharing must occur for 2000 was 12.83%.  Using the
same 30-year Treasury Bond average,  the compute level of return would be 14.33%
for 2001 through 2004. The law allows MidAmerican Energy to mitigate the sharing
of earnings  above the  threshold  return on common equity  through  accelerated
recovery of regulatory assets.

In  December 1999,  the Federal Energy  Regulatory  Commission  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  a  schedule  that  would  allow  the  regional
transmission organization to commence operating by December 15, 2001. On October
16, 2000, MidAmerican Energy filed with the Federal Energy Regulatory Commission
a plan for MidAmerican  Energy to comply with Order No. 2000 by participating in
the  formation of a for profit  independent  transmission  company.  MidAmerican
Energy continues in its effort to form such a company.

The United Kingdom

Since 1990, the electricity industry in Great Britain has seen the privatization
of  electric  generation,  supply  and  distribution,  and the  introduction  of
competition  in generation  and supply.  Electricity  is produced by generators,
transmitted  through the national grid transmission  system by The National Grid
Company  plc  ("NGC")  (or in  Scotland  by  Scottish  Power or  Scottish  Hydro
Electric)  and  distributed  to  customers by the  fourteen  Public  Electricity
Suppliers  ("PESs")  in their  respective  authorized  areas.  The  majority  of
customers are still supplied with electricity by their local PES, although there
are other suppliers  holding second tier supply licenses,  including  generators
and other PESs, who can compete to supply  customers  throughout  Great Britain.
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 is to be
replaced  by two  separate  licenses - the  Distribution  license and the Supply
license.  The Public  Electricity  Supplier  ("PES")  license  currently held by
Northern  Electric  plc is to be split so that  separate  subsidiaries  will own
licenses  for  distribution  and  energy  supply.  In order to  comply  with the
legislation  the  Company  has  submitted  a  draft  Statutory  Transfer  Scheme
("Scheme") to The  Secretary of State for Trade and Industry for  consideration.
Once  approved,  the Scheme  provides  for the  transfer  of certain  assets and
liabilities to the newly created  subsidiaries.  This will occur on a date to be
set by the Secretary of State for Trade and Industry,  currently  anticipated to
be in July 2001.

<PAGE>
Distribution.  Each of the PESs is required to offer terms for connection to its
distribution system to any person, and for use of its distribution system to any
authorized  electricity  operator.  In  providing  the  use of its  distribution
system, a PES must not discriminate  between its own supply business and that of
any other  authorized  electricity  supplier,  nor may its charges differ except
where  justified by  differences  in cost.  These  obligations  will transfer to
holders of Distribution licenses when the PES license is replaced.

Most revenue of the distribution  business is controlled by a distribution price
control  formula.  The Retail Price Index ("RPI") used in this formula  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 inflation  factor ("Xd") which was established by the regulator (and
continues to be set) at 3%. This formula  determines  the maximum  average price
per unit of electricity  distributed (in pence per kilowatt hour) which a PES is
entitled to charge.  The  distribution  price  control  formula  permits PESs 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 PES from year to year.  It is a control on revenue
that operates  independently of most of the PES's costs.  During the lifetime of
the price control,  additional  cost savings  therefore  contribute  directly to
profit.

In connection with the scheduled  distribution price control review concluded by
the regulator in 1999, Northern's allowable  distribution revenue was reduced by
24% with effect from April 1, 2000. As part of the review, the Xd factor was not
modified and therefore remained at 3%.

The distribution  prices allowable under the current  distribution price control
formula are expected to be reviewed by the  regulator at the  expiration  of the
formula's  scheduled  five-year  duration  in 2005.  The  formula may be further
reviewed at other times in the  discretion  of the  regulator,  including in the
next several years in connection  with the proposed  Information  and Incentives
Project  under which it is proposed  that two per cent of regulated  income will
depend upon the performance of the PES's distribution  system as measured by the
number and  duration  of customer  interruptions  and upon the level of customer
satisfaction monitored by the regulator.

Supply.  Subject to minor  exceptions,  all electricity  customers in the United
Kingdom must be supplied by a licensed  supplier.  Licensed  suppliers  purchase
electricity  and make  use of the  transmission  and  distribution  networks  to
achieve delivery to customers' premises.

There are  currently  two types of  licensed  suppliers:  PES (or "first  tier")
suppliers  and second tier  suppliers.  First tier  suppliers  are the successor
companies to the former state owned Area Electricity  Boards acting as suppliers
within their respective geographical authorized areas. Second tier suppliers are
those  suppliers  which supply  outside any area which is the subject of any PES
license which they may hold and include PESs supplying  outside their authorized
area, generators and independent suppliers. Northern holds both first and second
tier licenses. This distinction between first and second tier suppliers is to be
abolished  under the Utilities Act 2000.  From a date to be set by the Secretary
of State  for  Trade  and  Industry  there  will be only one  class of  licensed
supplier. This is anticipated to be in July 2001.

The price of  electricity  supplied by a PES to most of its  domestic  customers
within its authorized area is controlled by a formula.  As part of the scheduled
review  of the  formula  carried  out by the  regulator  in 1999,  Northern  was
required  to reduce  its  prices to most of its  domestic  customers  within its
authorized  area by about  11% from  April 1,  2000.  The price cap is due to be
reviewed with effect from April 1, 2002.

The Pool.  Virtually all electricity  generated in England and Wales was sold by
generators and bought by suppliers through the Pool described below. A generator
that is a Pool member and also a licensed  supplier must  nevertheless  sell all
the  electricity it generates  into the Pool,  and purchase all the  electricity
that it supplies from the Pool.  Because Pool prices  fluctuate,  generators and
suppliers  may  enter  into  bilateral  arrangements,   such  as  contracts  for
differences   ("CFDs"),   to  provide  a  degree  of  protection   against  such
fluctuations.

<PAGE>
The Pool  was  established  at the time of  privatization  for bulk  trading  of
electricity  in England and Wales between  generators  and  suppliers.  The Pool
reflects two principal  characteristics of the physical generation and supply of
electricity from a particular generator to a particular  supplier.  First, it is
not possible to trace  electricity  from a particular  generator to a particular
supplier.  Second,  it is not  practicable  to store  electricity in significant
quantities,  creating  the need for a constant  matching  of supply and  demand.
Subject to certain  exceptions,  all electricity  generated in England and Wales
must be sold and  purchased  through  the  Pool.  All  licensed  generators  and
suppliers  must become and remain  signatories  to the  Pooling  and  Settlement
Agreement,  which  governs the  constitution  and  operation of the Pool and the
calculation of payments due to and from generators and suppliers.  The Pool also
provides  centralized  settlement  of accounts and  clearing.  The Pool does not
itself supply electricity.

Prices for electricity have been set by the Pool daily for each one-half hour of
the  following  day based on the bids of the  generators  and a  complex  set of
calculations  matching supply and demand and taking account of system stability,
security and other costs. A settlement system is used to calculate prices and to
process  metered,  operational  and  other  data  and to  carry  out  the  other
procedures  necessary  to  calculate  the  payments  due under the Pool  trading
arrangements.  The settlement  system is administered  on a day-to-day  basis by
Energy  Settlements and Information  Services,  Limited, a subsidiary of NGC, as
settlement system administrator.

In order to hedge against Pool price  volatility,  parties  enter  Contracts for
Differences  ("CFDs").  Generally,  CFDs are contracts  between  generators  and
suppliers  that  have the  effect  of  fixing  the  price of  electricity  for a
contracted  quantity of  electricity  over a specific  time period.  Differences
between  the  actual  price set by the Pool and the agreed  prices  give rise to
difference  payments  between  the parties to the  particular  CFD. At any time,
Northern's forecast supply market demand is substantially hedged through various
types of agreements including CFDs.

Northern's  supply  business   generally  involves  entering  into  fixed  price
contracts  to  supply  electricity  to  its  customers.   Northern  obtains  the
electricity  to satisfy  its  obligations  under  such  contracts  primarily  by
purchases  from the Pool.  Because the price of  electricity  purchased from the
Pool varies,  Northern is exposed to risk arising from  differences  between the
fixed price at which it sells and the  fluctuating  prices at which it purchases
electricity, unless it can effectively hedge such exposure.

The United  Kingdom  government  introduced  legislation to reform the wholesale
trading market for  electricity by eliminating the Pool and creating a bilateral
wholesale  trading market.  The elimination of the Pool and the  introduction of
the New Electricity  Trading  Arrangements  ("NETA") occurred on March 27, 2001.
Elimination  of the Pool will create  risks of a mismatch  between the prices at
which Northern purchases  electricity from wholesale  suppliers and the price at
which it has, or will, contract to sell electricity to its customers. Northern's
ability to manage such risks at acceptable  levels will depend,  in part, on the
specifics of the supply contracts that Northern enters into,  Northern's ability
to implement and manage an appropriate contracting and hedging strategy, and the
development of an adequate market for hedging instruments.

Under NETA,  suppliers  will need to buy physical  electricity  from  generators
equal to the forecast demand of customers. NETA will create additional risks and
opportunities and in order to mitigate them,  Northern is developing a new suite
of information technology systems in coordination with industry leading software
development companies.

Regulatory, Energy and Environmental Matters

United States

The Company is subject to a number of environmental  laws and other  regulations
affecting  many  aspects of its  present  and future  operations.  Such laws and
regulations  generally  require  the  Company to obtain  and comply  with a wide
variety of licenses,  permits and other  approvals.  No assurance  can be given,
however, that in the future all necessary permits and approvals will be obtained
and  all  applicable  statutes  and  regulations  complied  with.  In  addition,
regulatory  compliance  for 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 project  value if projects  cannot
function as planned due to changing regulatory requirements or local opposition.
The Company  believes  that its  operating  power  facilities  are  currently in
material  compliance  with all  applicable  federal,  state and  local  laws and
regulations.  There can be no assurance  that existing  regulations  will not be
revised or that new regulations will not be adopted or become  applicable to the
Company which could have an adverse impact on its operations. In particular, the
independent  power  market in the United  States is  dependent  on the  existing
energy regulatory  structure,  including PURPA and its implementation by utility
commissions in the various states.

<PAGE>
Each of the  operating  domestic  power  facilities  partially  owned through CE
Generation  meets the  requirements  promulgated  under  PURPA to be  qualifying
facilities.   Qualifying  facility  status  under  PURPA  provides  two  primary
benefits.  First,  regulations under PURPA exempt qualifying facilities from the
Public  Utility  Holding  Company  Act  of  1935,  as  amended  ("PUHCA"),  most
provisions  of the Federal  Power Act (the "FPA") and the state laws  concerning
rates of electric  utilities,  and financial  and  organization  regulations  of
electric utilities.  Second, FERC's regulations  promulgated under PURPA require
that  (1)  electric  utilities  purchase  electricity  generated  by  qualifying
facilities, the construction of which commenced on or after November 9, 1978, at
a price based on the  purchasing  utility's  full Avoided Cost, (2) the electric
utility sell back-up,  interruptible,  maintenance and supplemental power to the
qualifying facility on a non-discriminatory  basis, and (3) the electric utility
interconnect with a qualifying facility in its service territory.

Currently,  Congress is considering  proposed legislation that would amend PURPA
by  eliminating  the  requirement  that  utilities  purchase   electricity  from
qualifying  facilities  at prices based on Avoided  Costs.  The Company does not
know  whether  such  legislation  will be passed  or what form it may take.  The
Company believes that if any such  legislation is passed,  it would apply to new
projects only and thus, although potentially  impacting the Company's ability to
develop  new  domestic  projects,  it would not  affect the  Company's  existing
qualifying facilities. There can be no assurance,  however, that any legislation
passed would not adversely impact the Company's existing domestic projects.

In addition,  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. On September 1, 1996, the
California legislature adopted an industry restructuring bill that would provide
for a phased-in competitive power generation industry with an independent system
operator and direct access to generation for all power  purchasers under certain
circumstances.  Under  the  bill,  consistent  with the  requirements  of PURPA,
existing  qualifying  facilities power sales  agreements  would be honored.  The
Company  cannot  predict  the  final  form or timing  of the  proposed  industry
restructuring or the impact on its operations.

The Clean Air Act  Amendments  of 1990  ("CAAA") was signed into law in November
1990.  Essentially all utility generating units are subject to the provisions of
the CAAA which address continuous emissions monitoring,  permit requirements and
fees and emissions of certain  substances.  MidAmerican  Energy has five jointly
owned  and  six  wholly  owned  coal-fired  generating  units,  which  represent
approximately  65%  of  MidAmerican  Energy's  electric  generating  capability.
MidAmerican  Energy's  generating units meet all requirements  under Title IV of
the CAAA. Title IV of the CAAA,  which is also  known as the Acid Rain  Program,
sets forth  requirements  for the emission of sulfur dioxide and nitrogen oxides
at electric utility generating stations.

State and federal  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  certain  of  the  Company's  existing
facilities,  increasing the risk of delay on construction  projects,  increasing
the Company's  cost of waste disposal and possibly  reducing the  reliability of
service  provided  by the Company  and the amount of energy  available  from the
Company's  facilities.  Any of such  items  could have a  substantial  impact on
amounts required to be expended by the Company in the future.

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 the Company,
which would result in increased  compliance costs, could have a material adverse
effect on the Company's results of operations.

<PAGE>
United Kingdom

Northern's  businesses  are subject to  numerous  regulatory  requirements  with
respect to the protection of the environment.  The Electricity Act obligates the
UK  Secretary  of State or the  Regulator  to take into  account  the  effect of
electricity  generation,  transmission  and supply  activities upon the physical
environment  when  approving  applications  for the  construction  of generating
facilities  and the  location of  overhead  power  lines.  The  Electricity  Act
requires Northern 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.  Northern  mitigates the effects its  proposals  have on natural and
man-made features and administers an environmental assessment when it intends to
lay  cables,  construct  overhead  lines or carry out any other  development  in
connection with its licensed activities.

The  Environmental  Protection Act of 1990 addresses waste management issues and
imposes certain  obligations and duties on companies which handle and dispose of
waste. Some of Northern's  distribution  activities  produce waste, but Northern
believes that it is in compliance with the applicable standards in such regard.

Possible adverse health effects of electromagnetic  fields ("EMFs") from various
sources, including transmission and distribution lines, have been the subject of
a number  of  studies  and  increasing  public  discussion.  Current  scientific
research is  inconclusive  as to whether EMFs may cause adverse health  effects.
The only United Kingdom standards for exposure to power frequency EMFs are those
promulgated  by the  National  Radiological  Protection  Board and relate to the
levels  above  which  non-reversible  physiological  effects  may  be  observed.
Northern fully complies with these standards.  However, there is the possibility
that passage of  legislation  and change of regulatory  standards  would require
measures to mitigate  EMFs,  with  resulting  increases in capital and operating
costs. In addition,  the potential  exists for public  liability with respect to
lawsuits brought by plaintiffs alleging damages caused by EMFs.

Northern  believes  that it has taken and  continues to take  measures to comply
with the applicable laws and governmental  regulations for the protection of the
environment.  There are no material legal or administrative  proceedings pending
against Northern with respect to any environmental matter.

The UK government has recently introduced into Parliament  legislation which, if
enacted,  will  facilitate  certain  aspects  of the  reform  of  the  wholesale
electricity  trading  market  described  above,  and  reform UK  utility  law in
connection  with  the  licensing  regime  for  electricity  and  gas  utilities,
electricity and gas regulatory institutions and procedures, and social, consumer
and environmental protection related to utilities.

Employees

As of December 31, 2000, the Company and its subsidiaries employed approximately
9,550 people.

As  of  December  31,  2000,   the  CalEnergy   Generation   platform   employed
approximately  500  people,  of  which  approximately  230  people  were  in the
Philippines.   None  of  CalEnergy  Generation's  employees  are  covered  by  a
collective bargaining agreement. Management believes that CalEnergy Generation's
relations with its employees are good.

As of December 31, 2000, Northern employed  approximately 3,560 people, of which
approximately  67% are represented by labor unions.  All Northern  employees who
are not party to a  personal  employment  contract  are  subject  to  collective
bargaining  agreements that are covered by eight separate  business  agreements.
These  arrangements  may be amended by joint agreement  between the trade unions
and  the  individual  business  through  negotiation  in the  appropriate  Joint
Business  Council.  Northern  believes that its relations with its employees are
good.

As of December 31, 2000, MidAmerican Energy employed approximately 3,720 people,
of which  approximately  one half are  represented by labor unions.  MidAmerican
Energy believes that its relations with its employees are good.

<PAGE>
As of December 31, 2000,  HomeServices employed  approximately 1,670 individuals
and had approximately  6,600 sales associates,  who are independent  contractors
and not  employees.  None of  HomeServices'  employees or sales  associates  are
covered  by  a  collective  bargaining   agreement.   Management  believes  that
HomeServices' relations with its employees and sales associates are good.

Item 2.  Properties

Property.  Northern  leases its principal  executive  offices in Newcastle  upon
Tyne, England.  Northern has both network and non-network land and buildings. At
December  31,  2000,   Northern   had  freehold  and   leasehold   interests  in
approximately 8,500 network properties, comprising principally substation sites.
Northern owns,  directly or indirectly,  the freehold or leasehold  interests of
such land and  buildings.  At December  31,  2000,  Northern  had  freehold  and
leasehold  interests  in  approximately  63  non-network  properties  comprising
chiefly offices, retail outlets, depots, warehouses and workshops.

MidAmerican Energy's utility properties consist of physical assets necessary and
appropriate  to render  electric  and gas  service in its  service  territories.
Electric   property   consists   primarily  of  generation,   transmission   and
distribution facilities.  Gas property consists primarily of distribution plant,
including feeder lines to communities served from natural gas pipelines owned by
others.  It  is  the  opinion  of  management  that  the  principal  depreciable
properties owned by MidAmerican Energy are in good operating  condition and well
maintained.

The electric  transmission  system of  MidAmerican  Energy at December 31, 2000,
included 897 miles of 345-kV  lines,  and 1,110 miles of 161-kV  lines.  The gas
distribution  facilities of  MidAmerican  Energy at December 31, 2000,  included
20,259  miles  of gas  mains  and  services.  Substantially  all  of the  former
Iowa-Illinois  Gas and Electric  Company  (predecessor  to  MidAmerican  Energy)
utility  property and franchises,  and  substantially  all of the former Midwest
Power Systems Inc. (predecessor to MidAmerican Energy) electric utility property
located in Iowa,  or  approximately  80% of gross utility  plant,  is pledged to
secure mortgage bonds.

The Company's most significant  physical  properties,  other than those owned by
Northern and  MidAmerican  Energy,  are its current  interest in operating power
facilities,  its plants under construction and related real property  interests.
The Company  also  maintains  an inventory  of  approximately  150,000  acres of
geothermal  property leases. The Company leases its principal  executive offices
and its offices in Manila.

HomeServices'  principal  offices  are  located  in  Edina,   Minnesota,   where
HomeServices leases approximately 46,000 square feet of office space. This lease
expires in 2003. In addition,  HomeServices  has a total of 160 branch  offices,
substantially  all of which are leased.  HomeServices'  office leases  generally
have initial terms ranging from three to ten years, with an option to extend the
lease for additional periods.  The leases are typically net leases,  which means
that HomeServices is required to pay property taxes,  utilities and maintenance.
HomeServices  believes that its present  facilities are adequate for its current
level of operations.

<PAGE>
Item 3.  Legal Proceedings

The Company and its subsidiaries have no material legal  proceedings  except for
the following:

Southern California Edison

The  Imperial  Valley  Projects  have  filed a  lawsuit  seeking  a court  order
requiring  Edison  to make  the  required  payments  under  the  Power  Purchase
Agreements. See page 16.

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 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
         that 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 contingent counterclaims. The contingent
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 NPPD has the duty to repay all amounts that MidAmerican Energy
         has  prefunded for  decommissioning  in the event the NPPD operates the
         plant after the term of the power purchase agreement;

(3)      that the  NPPD is equitably  estopped  from  continuing to operate  the
         plant after the term of the power purchase agreement;

(4)      that  the NPPD has  granted  MidAmerican  Energy an  option to continue
         taking 50% of the power from the plant;

(5)      that the term  "monthly  power costs" as defined in the power  purchase
         agreement  does  not  include  costs  and  expenses   associated   with
         decommissioning the plant;

(6)      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;

(7)      that transition costs are not included in any decommissioning costs and
         expenses;

(8)      that the  NPPD  has breached its duty to MidAmerican  Energy in  making
         investments of decommissioning funds;

<PAGE>
(9)      that reserves in named accounts are excessive and should be refunded to
         MidAmerican Energy; and

(10)     that  the  NPPD  must  credit   MidAmerican   Energy  for  payments  by
         MidAmerican Energy for low-level radioactive waste disposal.

On October 6, 1999,  the court  rendered  summary  judgment  for the 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,  two,  three and five in the second  paragraph
above).  The court referred all remaining  issues in the case to mediation,  and
cancelled the November 1999 trial date.

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  issues  one  and  five  in  the  second  paragraph  above.
Additionally,   it  remanded  the  case  for  trial  on  all  other  claims  and
counterclaims.  It is not likely that a trial will occur prior to late spring or
early summer of 2001.

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

Not applicable.


<PAGE>

                                     PART II

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

As of March 14, 2000, the Company's  equity  securities are owned by the members
of the Investor  Group and are not  registered  with the Securities and Exchange
Commission pursuant to the Securities Act of 1933, as amended, listed on a stock
exchange or otherwise publicly held or traded.

Item 6.  Selected Financial Data

Reference is made to Part IV of this report.

Item 7.  Management's Discussion and Analysis of Financial Condition and Results
           of Operations

Reference is made to Part IV of this report.

Item 7A. Qualitative and Quantitative Disclosures About Market Risk

Reference is made to Part IV of this report.

Item 8.  Financial Statements and Supplementary Data

Reference is made to Part IV of this report.

Item 9.  Changes  in  and  Disagreements  with  Accountants  on  Accounting  and
         Financial Disclosure

Not applicable.



<PAGE>

                                    PART III

                                   MANAGEMENT

Item 10.  Directors, Executive and Other Officers of the Company and Significant
             Subsidiaries

The Company's  management  structure is organized  functionally  and the current
executive and other officers of the Company and their positions are as follows:

Name                       Position

David L. Sokol             Chairman of the Board & Chief Executive Officer
Gregory E. Abel            President & Chief Operating Officer
Patrick J. Goodman         Senior Vice President & Chief Financial Officer
Steven A. McArthur         Senior Vice President, General Counsel & Secretary
Keith D. Hartje            Senior Vice President & Chief Administrative Officer
Ronald W. Stepien          President, MidAmerican Energy
P. Eric Connor             President & Chief Operating Officer, Northern

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

DAVID L. SOKOL,  44,  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 PKS, and Ogden Projects, Inc.

GREGORY E. ABEL, 38, President and Chief Operating Officer.  Mr. Abel joined the
Company in 1992 and initially served as Vice President and Controller.  Mr. Abel
is a  Chartered  Accountant  and  from  984 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,  34, Senior Vice President and Chief Financial Officer.  Mr.
Goodman joined the Company in 1 995, and served in various accounting  positions
including Senior Vice President and Chief Accounting  Officer.  Prior to joining
the Company,  Mr. Goodman was a financial manager for National Indemnity Company
and a senior associate at Coopers & Lybrand.

STEVEN A. McARTHUR,  43, Senior Vice  President,  General Counsel and Secretary.
Mr.  McArthur  joined  the Company in  February  1991 and has  served in various
executive  capacities.  From 1988 to 1991  he  was an  attorney in the Corporate
Finance Group at Shearman & Sterling in San Francisco.  From 1984 to 1988 he was
an  attorney in the  Corporate  Finance  Group at  Winthrop,  Stimson,  Putnam &
Roberts in New York.

KEITH D. HARTJE, 51, 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.

RONALD W. STEPIEN,  54,  President,  MidAmerican  Energy.  Mr. Stepien served as
Executive  Vice  President  from  November 1, 1996 to October 31, 1998 and Group
Vice President  from 1995 to November 1, 1996.  Prior to that Mr. Stepien served
as Vice  President of  Iowa-Illinois  Gas and Electric  Company,  a  predecessor
company, from 1990 to 1995.

<PAGE>
P. ERIC CONNOR,  52, President and Chief Operating  Officer,  Northern Electric.
Mr. Connor joined Northern in 1992 as a Director.  Prior to joining Northern, he
was a  Director  at NEI  Reyrolle  Ltd.  and  prior  to that,  his  appointments
included:  deputy  group  head of  engineering,  National  Nuclear  Corporation;
manager computer systems, NEI Electronics (C&I Systems); systems engineer, Davy-
Leowy; software engineer, Marconi Space & Defense.

Item 11.  Executive Compensation

To be filed by amendment.

Item 12.   Security Ownership of Certain Beneficial Owners and Management

To be filed by amendment.

Item 13.  Certain Relationships and Related Transactions

To be filed by amendment.


<PAGE>

PART IV

Item 14.   Exhibits, Financial Statement Schedules and Reports on Form 8-K

         (a)  Financial Statements and Schedules

         1.   Financial Statements (included herein)
                                                                        Page No.
         Selected Consolidated Financial Data................................38
         Management's Discussion and Analysis of Financial Condition
              And Results of Operations......................................39
         Qualitative and Quantitative Disclosures About Market Risk..........53
         Consolidated Balance Sheets as of December 31, 2000 and 1999........57
         Consolidated Statements of Operations
              For the Three Years Ended December 31, 2000, 1999 and 1998.....58
         Consolidated Statements of Stockholders' Equity
              For the Three Years Ended December 31, 2000, 1999 and 1998.....59
         Consolidated Statements of Cash Flows
              For the Three Years Ended December 31, 2000, 1999 and 1998.....60
         Notes to Consolidated Financial Statements..........................61
         Independent Auditor's Report........................................96

         2.   Financial Statement Schedules

                                                                        Page No.
         Schedule I, Financial Statements of the Company

              (Parent Company only)..........................................97

         (b)   Reports on Form 8-K

         None.

         (c)   Exhibits

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

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

         Not applicable.


<PAGE>
<TABLE>
                      SELECTED CONSOLIDATED FINANCIAL DATA

                                 (In thousands)
<CAPTION>
                                                                                MEHC (Predecessor)
                                                     ---------------------------------------------------------------------
                                  March 14, 2000     January 1, 2000
                                      through           through                        Year Ended December 31,
                                                                     -----------------------------------------------------
                                December 31,2000(1) March 13, 2000      1999 (2)       1998 (3)       1997          1996 (4)
                                ------------------- --------------   ------------    -----------    ---------     ----------
Income Statement Data:
<S>                                    <C>            <C>             <C>            <C>           <C>            <C>
Operating revenue                      $3,945,716     $1,043,072      $4,128,737     $2,555,206    $2,166,338     $518,934
Total revenues                          4,040,598      1,062,556       4,410,616      2,682,711     2,270,911      576,195
Total costs and expenses                3,821,394        971,386       4,053,547      2,410,658     2,074,051      435,791
Income before provision for
   income taxes                           219,204         91,170         357,069        272,053       196,860(6)   140,404
Minority interest                          84,670          8,850          46,923         41,276        45,993        6,122
Income before change in
   accounting principle
   and extraordinary item                  81,257         51,312         216,671(5)     137,512        51,823(6)    92,461
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)                          81,257         51,312         167,230(5)     127,003       (84,027)(6)   92,461

Balance Sheet Data:

Total assets                          $11,680,651            N/A     $10,766,352     $9,103,524    $7,487,626   $5,630,156
Total liabilities                       8,981,061            N/A       8,978,924      7,598,040     5,282,162    4,181,052
Company-obligated mandatory
   redeemable preferred securities
   of subsidiary trusts                   786,523            N/A         450,000        553,930       553,930      103,930
Subsidiary-obligated mandatorily
   redeemable preferred securities
   of subsidiary trusts                   100,000            N/A         101,598              -             -            -
Preferred securities of subsidiaries      145,686            N/A         146,606         66,033        56,181      136,065
Total stockholders' equity              1,576,401            N/A         994,588        827,053       765,326      880,790

</TABLE>
     (1)  Reflects the Teton Transaction on March 14, 2000.
     (2)  Reflects the MidAmerican  Merger on March 12, 1999, the disposition of
          Coso Joint  Ventures on February 26, 1999 and the  disposition  of 50%
          ownership interest in CE Generation on March 3, 1999.

     (3)  Reflects the acquisition of KDG on January 2, 1998.
     (4)  Reflects  the  acquisitions  of  Northern,  Falcon  Seaboard  and  the
          Partnership Interest owned for a portion of the year.

     (5)  Includes $81.5 million for non-recurring Indonesia gain on settlement,
          gains  on  sales  of  McLeod  and   qualified   facilities,   Northern
          restructuring charges and Teton Transaction costs.

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


<PAGE>

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  Company's  financial  condition and results of
operations  during  the  periods  included  in the  accompanying  statements  of
operations.

As a result of the Teton  Transaction,  the MidAmerican  Merger and the sales of
Coso and an interest in CE Generation,  the Company's future results will differ
significantly from the Company's historical results.

Teton Transaction

On October 24, 1999,  the Company and entities  representing  an investor  group
comprised of Berkshire Hathaway Inc. ("Berkshire Hathaway"),  Walter Scott, Jr.,
a director of the  Company,  and David L. Sokol,  Chairman  and Chief  Executive
Officer of the  Company,  executed  a  definitive  agreement  and plan of merger
whereby the investor 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. The 11% trust preferred securities have
a liquidation  preference of $25 each and are subject to mandatory redemption in
ten equal semi-annual  installments commencing December 15, 2005. 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.

Business of MEHC

The Company 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  four  separate  platforms:  MidAmerican,  Northern,  CalEnergy
Generation and HomeServices.

MidAmerican

MidAmerican  Energy  ("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, 2000,
MidAmerican  Energy had 669,000  retail  electric  customers and 647,000  retail
natural gas customers.

In addition to retail sales,  MidAmerican  Energy  delivers  electric  energy to
other  utilities,  marketers  and  municipalities  who  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.

Most  of  MidAmerican   Energy's  business  is  conducted  in  a  rate-regulated
environment and  accordingly,  many of its decisions as to the source and use of
resources  and other  strategic  matters are evaluated  from a utility  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.

<PAGE>
Northern

The operations of Northern Electric plc  ("Northern"),  an indirect wholly owned
subsidiary of the Company,  consist  primarily of the distribution and supply of
electricity,  supply of natural gas and other auxiliary businesses in the United
Kingdom.  Northern's  operations are seasonal in nature with a  disproportionate
percentage of revenues and earnings  historically  being earned in the Company's
first and fourth quarters.

Northern  receives  electricity from the national grid  transmission  system and
distributes  it to  customers'  premises  using  its  network  of  transformers,
switchgear  and  cables.  Substantially  all  of  the  customers  in  Northern's
authorized  area are connected to  Northern's  network and can only be delivered
electricity through Northern's distribution system,  regardless of whether it is
supplied by Northern's own supply business or by other suppliers, thus providing
Northern  with  distribution  volume that is stable from year to year.  Northern
charges  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.

Northern's supply business  primarily involves the bulk purchase of electricity,
through a central  pool,  and  subsequent  resale to individual  customers.  The
supply  business  generally is a high volume  business  that tends to operate at
lower profitability  levels than the distribution  business.  As of December 31,
2000, Northern supplied electricity to approximately 1.1 million customers.

Northern also competes to supply gas inside and outside its authorized  area. As
of December 31, 2000,  Northern supplies gas to approximately  470,000 customers
in the residential market.

CalEnergy Generation

The Company indirectly owns the Upper Mahiao,  Malitbog and Mahanagdong Projects
(collectively,  the "Philippine  Projects"),  which are geothermal  power plants
located on the island of Leyte in the  Philippines.  For purposes of  consistent
presentation,  capacity  amounts  for Upper  Mahiao,  Malitbog  and  Mahanagdong
(collectively,  the  "Philippine  Projects")  are  119,  216  and  165  net  MW,
respectively.  Each  plant  possesses  an  operating  margin  which  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.

On February 8, 1999,  the Company  created a new  subsidiary,  CE Generation LLC
("CE  Generation")  and  subsequently  transferred  its interest in the Imperial
Valley  Projects and Gas Plants to CE  Generation.  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").
Turbo  became  operational  in the third  quarter  of 2000.  Salton Sea V became
operational in the second quarter of 2000.  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 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.
Prior to that date, CE Generation results were fully consolidated.

On  February  26,  1999,  the  Company  closed the sale of all of its  ownership
interests in the Navy I, Navy II and BLM,  collectively the Coso Joint Ventures,
to Caithness Energy, LLC for $205 million in cash.

<PAGE>
HomeServices

The Company owns approximately 83% of HomeServices.Com,  Inc.  ("HomeServices"),
the second largest  residential  real estate brokerage firm in the United States
based on aggregate closed  transaction  sides in 1999 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 primarily
under the Edina Realty, Iowa Realty,  J.C. Nichols  Residential,  CBSHOME,  Paul
Semonin  Realtors,  Long Realty and Champion Realty brand names in the following
twelve states: Minnesota, Iowa, Arizona, Kansas, Missouri,  Kentucky,  Nebraska,
Wisconsin,  Indiana,  Maryland,  North  Dakota  and South  Dakota.  HomeServices
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, 1999.  HomeServices'  major markets  consist of the  following  metropolitan
areas:  Minneapolis and St. Paul, Minnesota;  Des Moines, Iowa; Omaha, Nebraska;
Kansas  City,  Kansas;  Louisville,  Kentucky;  Springfield,  Missouri;  Tucson,
Arizona and Annapolis, Maryland.

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 its  predecessor
(referred  to as "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  Teton  Transaction.  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 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 Teton  Transaction  and the MidAmerican
Merger 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 $4,988.8
million  compared with $4,517.0 million for the same period in 1999, an increase
of 10.4%.  MidAmerican  operating  revenue increased for the year ended December
31, 2000 to $2,330.7  million from $1,816.1 million for the same period in 1999,
primarily  due to  increases  in  nonregulated  gas  sales and  higher  rates in
regulated gas. Northern Electric  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  relates to the increase of
revenue at HomeServices due to acquisitions in late 1999.

<PAGE>
The following data represents sales from MidAmerican Energy:

                                                       Year Ended December 31,

                                                        2000             1999
                                                     -----------      ----------

Electricity Retail Sales (GWh).................        16,715           16,007

Electricity Sales for Resale (GWh).............         6,941            7,168

Regulated and Nonregulated 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 sales for resale 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 facility 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 nonregulated sales.

The following  data  represents  the supply and  distribution  operations in the
U.K.:

                                                       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 is 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 is due to changes in demand in the  franchise  area.  The  increase  in gas
supplied in 2000 from 1999  reflects  higher volume in the U.K.  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 Teesside and gains on other asset sales in
1999,  partially  offset by proceeds on  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 McLeod Class A common stock, through a secondary offering
by McLeod,  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 Coso and an interest in CE  Generation,  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 sub-
sidiaries  of the  Company,  and P.T.  PLN  (Persero),  an  Indonesian  national
electric utility.

<PAGE>
Pro forma  cost of sales  for the year  ended  December  31,  2000 was  $2,783.5
million  compared with $2,342.8 million for the same period in 1999, an increase
of 18.8%.  The increase  relates 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 Northern  primarily due to
higher production at CE Gas.

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 Casecnan, Cordova and Zinc.

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  Teton
Transaction.

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 is 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  includes  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.

Results of Operations For The Years Ended December 31, 1999 and 1998

Operating  revenue  increased  in the year ended  December  31, 1999 to $4,128.7
million from  $2,555.2  million for the same period in 1998,  a 61.6%  increase.
Northern's  operating  revenue  increased in the year ended December 31, 1999 to
$2,072.2  million from $1,823.9  million for the same period in 1998,  primarily
due to higher  volumes  of gas  supplied  as well as higher  electricity  supply
revenues. The MidAmerican Merger added $1,687.9 million in the period from March
12, 1999 through December 31, 1999. These increases were partially offset by the
sales of Coso and reporting  the 50% interest in CE Generation  using the equity
method beginning March 3, 1999.

<PAGE>
The following data  represents  sales from utility  operations  for  MidAmerican
Energy.  The financial  results of MidAmerican  Energy are consolidated with the
Company beginning on March 12, 1999.

                                                       Year Ended December 31,

                                                         1999            1998
                                                     ------------    -----------

Electricity Retail Sales (GWh)...............           16,007          16,088

Electricity Sales for Resale (GWh)...........            7,168           6,186

Regulated and Nonregulated Gas

Supplied (Thousands of MMBtus)...............          138,387         139,563


The following  data  represents  the supply and  distribution  operations in the
U.K.:

                                                       Year Ended December 31,

                                                         1999            1998
                                                     -------------   -----------

Electricity Supplied (GWh).....................         17,984          15,313

Electricity Distributed (GWh)..................         15,943          15,904

Gas Supplied (Thousands of MMBtus).............         48,435          35,950

The increases in electricity  supplied for the year ended December 31, 1999 from
the same period in 1998 are due primarily to the increase in supply  volumes for
customers   outside  of  the  franchise   area.  The  increases  in  electricity
distributed  for the year ended  December  31, 1999 from the same period in 1998
are due to  changes  in demand  in the  franchise  area.  The  increases  in gas
supplied in 1999 from 1998  reflects  the  increased  volume as the domestic gas
supply  business in the U.K.  opened up to competition as a result of regulatory
changes and the successful dual fuel marketing campaign.

Interest  and other  income  increased  for the year ended  December 31, 1999 to
$143.2  million from $127.5 million in the same period in 1998. The increase was
due to the  MidAmerican  Merger  and  the  addition  of  equity  income  from CE
Generation  partially  offset by the  reduction of operator  fees related to the
CalEnergy Generation facilities that were sold in 1999.

The gains on non-recurring items of $138.7 million in 1999 represent the pre-tax
gain on the sale of the qualified  facilities of $20.2 million, the pre-tax gain
on the sale of McLeod  common stock of $78.2 million and the pre-tax gain on the
Indonesia settlement of $40.3 million.

Cost of sales increased in the year ended December 31, 1999 to $2,143.9  million
from  $1,258.5  million  from the same  period in 1998,  a 70.4%  increase.  The
increase is primarily due to the  MidAmerican  Merger and higher  volumes of gas
and  electricity  supplied at  Northern.  The  MidAmerican  Merger  added $655.2
million in the period March 12, 1999 through December 31, 1999.

Operating  expense  increased  in the year to date ended  December  31,  1999 to
$1,001.4  million  from $471.4  million  for the same  period in 1998,  a 112.4%
increase.  The MidAmerican  Merger added $609.1 million in the period from March
12, 1999 through December 31, 1999, partially offset by the sales of Coso and an
interest in CE Generation.

Depreciation and amortization increased in the year to date December 31, 1999 to
$427.7 million from $333.4 million in the same period in 1998, a 28.3% increase.
The  MidAmerican  Merger added $187.3  million in the period from March 12, 1999
through  December  31, 1999,  partially  offset by the sales of Coso and the 50%
interest in CE Generation.

Interest  expense,  less  amounts  capitalized,  increased  in the  year to date
December 31, 1999 to $426.2 million from $347.3 million,  a 22.7% increase.  The
increase is  primarily  due to the  MidAmerican  Merger and the greater  average
outstanding debt balances.

The losses on non-recurring items of $54.4 million in 1999 represent the pre-tax
loss of $47.7  million  related to the costs  associated  with the  reduction of
Northern's  workforce  and the  $6.7  million  of  costs  related  to the  Teton
Transaction.

The  provision  for income taxes  increased  marginally to $93.5 million in 1999
from $93.3  million in 1998.  After  adjusting for the  non-recurring  gains and
losses and the deductible dividends on preferred  securities,  the effective tax
rate was 38.7% and 39.5% in 1999 and 1998 respectively.

<PAGE>
Minority interest consists of dividends on preferred  securities of subsidiaries
and minority ownership of HomeServices.  Minority interest increased in the year
ended  December 31, 1999 to $46.9  million from $41.3 million in the same period
in 1998, a 13.6%  increase.  The increase is  primarily  due to the  MidAmerican
Merger that has minority interests in the form of preferred stock outstanding.

Due to the early  retirements of the Senior Discount Notes, the Limited Recourse
Notes and the 9.5% Senior Notes,  the Company recorded  extraordinary  losses of
approximately $49.4 million, net of tax, in the year ended December 31, 1999.

During 1998, the Company recognized an extraordinary  loss of $7.1 million,  net
of tax, related to the redemption of the Senior Discount Notes. The Company also
recognized  the  cumulative  effect of a change in accounting  principle of $3.4
million,  net of tax, by adopting Statement of Position 98-5,  "Reporting on the
Costs of Start-Up Activities."

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's  unrestricted  cash and cash  equivalents  were $38.2  million at
December  31, 2000 as  compared to $316.3  million at  December  31,  1999.  The
majority of this  decrease was due to the cash used to partially  fund the Teton
Transaction.  In addition,  the Company recorded separately  restricted cash and
investments  of $90.9 million and $291.7  million at December 31, 2000 and 1999,
respectively.  The restricted  cash balance as of December 31, 2000 is comprised
primarily of amounts  deposited in  restricted  accounts  from which the Company
will fund the various projects under construction,  and the Philippine Projects'
cash reserves for the service of debt obligations.

Teton Transaction

On October 24, 1999,  the Company and entities  representing  an investor  group
comprised of  Berkshire  Hathaway  Inc.,  Walter  Scott,  Jr., a director of the
Company and David L. Sokol, Chairman and Chief Executive Officer of the Company,
executed a definitive  agreement and plan of merger  whereby the investor  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 closed on March 14,
2000 and Berkshire Hathaway invested approximately $1.24 billion in common stock
and  non-dividend  paying  convertible  preferred stock and  approximately  $455
million in 11%  nontransferable  trust preferred  securities due March 14, 2010.
The 11% trust preferred securities have a liquidation preference of $25 each and
are  subject  to  mandatory  redemption  in ten equal  semi-annual  installments
commencing  December 15, 2005. 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.

Financing Activities

On June 30, 2000,  the Company  redeemed the  remaining  $4.2 million of Limited
Recourse Notes at a redemption price of 104.9375% plus accrued interest.

Throughout  2000,  CalEnergy  Capital  Trust II, a  subsidiary  of the  Company,
redeemed  approximately  477,000 shares of preferred  securities at an aggregate
cost of  approximately  $19.5  million.  Prior to the  Teton  Transaction,  each
preferred  security  was  convertible  at anytime  into shares of the  Company's
common  stock  based on a stated  conversion  rate.  As a  result  of the  Teton
Transaction,  in lieu of shares of the Company's common stock,  holders of these
preferred  securities  received $35.05 for each share of common stock they would
have been entitled to receive on conversion.

<PAGE>
Construction

Minerals Extraction

The  Company  developed  and 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 (the  "Salton Sea  Extraction
Project")  as well  as the  production  of  power  to be used in the  extraction
process. A pilot plant has successfully  produced commercial quality zinc at the
Company's Imperial Valley Projects.  The Company intends to sequentially develop
facilities for the extraction of manganese,  silver,  gold, lead, boron, lithium
and other products as it further develops the extraction technology. The Company
is also investigating  producing silica as an extraction project. Silica is used
as a filler for such products as paint, plastics and high temperature cement.

CalEnergy  Minerals LLC, an indirect wholly owned subsidiary of the Company,  is
constructing  the  Zinc  Recovery  Project  that  will  recover  zinc  from  the
geothermal  brine (the "Zinc Recovery  Project").  Facilities  will be 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 mid-2001. 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  is  being   constructed  by  Kvaerner  U.S.  Inc.
("Kvaerner")  pursuant  to a date  certain,  fixed-price,  turnkey  engineering,
procurement  and   construction   contract  (the  "Zinc  Recovery   Project  EPC
Contract").  Kvaerner is a wholly owned indirect  subsidiary of Kvaerner ASA, an
international  engineering  and  construction  firm  experienced  in the metals,
mining and  processing  industries.  Total project  costs,  including  financing
costs,  of the Zinc  Recovery  Project are expected to be  approximately  $200.9
million.  The Company has incurred  approximately  $165.6  million of such costs
through December 31, 2000.

Casecnan

CE Casecnan  Water and Energy  Company,  Inc.,  a  Philippine  corporation  ("CE
Casecnan")  which at  completion  of the  Casecnan  Project is expected to be at
least 70% indirectly owned by the Company, is constructing the Casecnan Project,
a combined irrigation and 150 net MW hydroelectric power generation project (the
"Casecnan  Project")  located in the central  part of the island of Luzon in the
Republic of the Philippines.

CE Casecnan has entered into a fixed-price,  date certain,  turnkey engineering,
procurement  and  construction  contract to  complete  the  construction  of the
Casecnan  Project (the  "Casecnan  Construction  Contract").  The work under the
Casecnan  Construction Contract is being conducted by a consortium consisting of
Cooperative  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 Casecnan  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 lender's 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.
Accordingly,  the Casecnan Project is now expected to become  operational by the
third quarter of 2001.  The delay in completion is  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.

<PAGE>
The receipt of the working  schedule does not change the Guaranteed  Substantial
Completion  Date under the  Replacement  Contract,  and the  Contractor is still
contractually  obligated  either to complete the  Casecnan  Project by March 31,
2001 or to pay delay liquidated  damages.  As a result of receipt of the working
schedule,  however,  CE  Casecnan  has 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, the 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 (the
"Shareholder  Support  Letter") to cover  additional  costs  resulting  from the
Contractor's schedule delay.

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 force majeure events. In a March 20, 2001 Supplement to Request for
Arbitration, the Contractor also seeks compensation for alleged additional costs
it incurred from the claimed force majeure  events to the extent it is unable to
recover from its insurer.  CE Casecnan  believes  such  allegations  are without
merit and intends to vigorously defend the Contractor's claims.

The Republic of the Philippines  ("RP") has recently been  experiencing a period
of political unrest and governmental  uncertainty relating to the impeachment of
President  Estrada  which  resulted  in a change in the  Presidency  and related
changes to the RP cabinet and overall government administration.

Although the obligations of the National  Irrigation  Administration  ("NIA") to
make  payments to CE Casecnan for water and  electricity  fees under the Project
Agreement  with NIA and the  obligations  of the RP under the related  sovereign
Performance Undertaking are in no way dependent on maintaining any particular RP
administration  in  place or on any  particular  government's  annual  budgetary
appropriations,  it is  possible  that  if the  recent  Philippine  governmental
uncertainty  would  reoccur,  it could  have an adverse  impact on the  Casecnan
Project,  which, as noted above, is scheduled to commence  commercial  operation
and commerce receiving payments in 2001.

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,  CE  Casecnan 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.  Although
the  transmission  line is  complete,  NIA has not yet  installed  the  Casecnan
Project's metering equipment. Accordingly, no liquidated damages payments to NIA
have been made.

CE  Casecnan'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 CE
Casecnan, including the Company, and no directors,  officers or employees of the
Company  will  guarantee  or be in any way liable for  payment of CE  Casecnan's
obligations.  As a result, payment of CE Casecnan's obligations depends upon the
availability  of  sufficient  revenues  from CE  Casecnan's  business  after the
payment of operating expenses.

NIA's payments of obligations  under the Project Agreement are expected to be CE
Casecnan's  sole  source  of  operating  revenues.   Because  of  CE  Casecnan's
dependence on NIA, any material failure of NIA to fulfill its obligations  under
the  Project  Agreement  and  any  material  failure  of the RP to  fulfill  its
obligations  under the Performance  Undertaking would  significantly  impair the
ability of CE Casecnan to meet its existing and future obligations.

<PAGE>
Cordova

Cordova  Energy  Company  LLC  ("Cordova  Energy"),  an  indirect  wholly  owned
subsidiary  of the Company,  has  commenced  construction  of a 537 MW gas-fired
power plant in the Quad Cities,  Illinois area (the "Cordova Project").  Cordova
Energy has entered into an  engineering,  procurement and  construction  ("EPC")
contract  with Stone & Webster  Engineering  Corporation  ("SWEC")  to build the
project.  Total project costs are estimated to be approximately  $288.9 million.
The construction of the Cordova Project is expected to be completed in mid-2001.

Cordova  Energy has entered into a power sales  agreement with a unit of El Paso
Energy  Corporation ("El Paso").  Under the power sales agreement,  El Paso will
purchase all the capacity and energy from the project  until  December 31, 2019.
However,  Cordova Energy has the option to elect on an annual basis to retain up
to 50% of the project  capacity and energy for sales to others.  Cordova  Energy
has exercised this option for the full 50% for the first 3 years and has entered
into a power sales  agreement to sell this  capacity  and energy to  MidAmerican
Energy.

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.  As part of the
financing,  approximately $93.5 million of 8.64% Series A-1 Senior Secured Bonds
due in 2019 were issued.  An additional $31.3 million of 8.79% Series A-2 Senior
Secured  Bonds were issued on December 15, 1999,  $29.3  million of 9.07% Series
A-3 Senior  Secured Bonds were issued on March 15, 2000,  $58.1 million of 8.82%
Series A-4 Senior  Secured  Bonds were issued on June 15, 2000 and $12.8 million
of 8.48% Series A-5 Senior Secured Bonds were issued September 15, 2000. Cordova
Funding has loaned the  proceeds  to Cordova  Energy.  The Company has  incurred
$224.5 million of  construction  costs through  December 31, 2000.  Total equity
funding is expected to be approximately $63.9 million.

SWEC's  parent,  Stone & Webster,  Incorporated,  voluntarily  filed  Chapter 11
bankruptcy on September 2, 2000 and has sold  substantially all of its assets to
Shaw Group,  Inc. Shaw Group,  Inc. has agreed to complete  substantially all of
Stone &  Webster's  contracts  for  current and future  projects  including  the
Cordova  Project.  The Company  does not believe this  situation  will cause any
material adverse effect on the final completion of the Cordova Project or on the
Company.

Accounting Effects of Industry Restructuring

A possible  consequence of  competition in the utility  industry is that SFAS 71
may no longer apply.  SFAS 71 sets forth  accounting  principles  for operations
that are  regulated  and meet certain  criteria.  For  operations  that meet the
criteria,  SFAS 71 allows,  among other things, the deferral of costs that would
otherwise be expensed when incurred. With exception of the generation operations
serving the Illinois jurisdiction, MidAmerican Energy's electric and gas utility
operations   currently   meet  the  criteria   required  by  SFAS  71,  but  its
applicability  is  periodically  reexamined.  If other  portions of  MidAmerican
Energy's utility  operations no longer meet the criteria of SFAS 71, MidAmerican
Energy  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 resulting  legislation.  As of December 31, 2000,  the Company
had $240.9 million of regulatory assets on its consolidated balance sheet.

Domestic Rate Matters: Electric

Under a 1997  pricing  plan  settlement  agreement  resulting  from an IUB  rate
proceeding,  electric  prices  for  MidAmerican  Energy's  Iowa  industrial  and
commercial  customers  were  reduced  through  a retail  access  pilot  project,
negotiated  individual electric contracts and a tariffed rate reduction for some
non-contract commercial customers.

<PAGE>
The negotiated electric contracts have differing terms and conditions as well as
prices. The vast majority of the contracts expire during the period 2003 through
2005,  although some large  customers have contracts  extending to 2008. Some of
the  contracts  have  price  renegotiations  and  early  termination  provisions
exercisable  by either  party.  Prices are set as fixed  prices;  however,  many
contracts allow for potential price  adjustments  with respect to  environmental
costs,  government imposed public purpose programs,  tax changes, and transition
costs. While the contract prices are fixed (except for the potential  adjustment
elements),  the costs MidAmerican  Energy incurs to fulfill these contracts will
vary. On an aggregate basis the annual revenues under contract are approximately
$180 million.

Under a 1997 pricing plan settlement  agreement,  if MidAmerican Energy's annual
Iowa electric  jurisdictional return on common equity exceeds 12%, then earnings
above the 12% level will be shared  equally  between  customers and  MidAmerican
Energy. If the return exceeds 14%, then two-thirds of MidAmerican Energy's share
of those earnings above the 14% level will be used for  accelerated  recovery of
certain  regulatory  assets.  During 2000,  MidAmerican  Energy  credited  $14.8
million to its Iowa non-contract customers related to the return calculation for
1999 which was  approved  by the IUB,  subject to  additional  refund.  In 2000,
MidAmerican  Energy accrued $21.6 million for customer  credits relating to 2000
operations.  This Iowa electric  retail revenue  sharing plan remained in effect
through the year 2000.  The rates  established  by the pricing  plan  settlement
agreement  will  remain in effect  until  either the plan is  renegotiated  or a
change in rates is approved by the IUB pursuant to a rate proceeding.

On March 14, 2001,  the Office of Consumer  Advocate of the Iowa  Department  of
Justice filed a petition with the IUB to reduce MidAmerican Energy's Iowa retail
electric  rates by  approximately  $77  million  annually.  This  filing will be
contested by  MidAmerican  Energy and,  under Iowa law, the IUB must rule on the
petition within ten months from March 14, 2001. Iowa law provides that the rates
collected  after the filing of the petition are subject to refund with  interest
if they exceed rates finally approved by the IUB.

The pricing plan settlement  agreement precluded  MidAmerican Energy from filing
for increased  rates prior to January 1, 2001,  unless the return fell below 9%.
Other parties  signing the  agreement  were  prohibited  from filing for reduced
rates prior to 2001 unless the return,  after  reflecting  credits to customers,
exceeded  14%.  The  agreement  also  eliminated   MidAmerican  Energy's  energy
adjustment clause,  and, as a result, the cost of fuel is not directly passed on
to customers.

UK Rate Matters:

Distribution

Northern  charges  access  fees  for the use of the  distribution  system.  Most
revenue of the  distribution  business 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 RPI reflects the
average of the twelve months'  inflation rates recorded for the previous July to
December  period and Xd is 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.  The
formula determines the maximum average price per unit of electricity distributed
(in pence per  kilowatt  hour)  which a PES is  entitled  to  charge.  The price
control does not seek to constrain the profits of a PES from year to year. It is
a control on revenue that operates  independently of the PES's costs. During the
lifetime of the price  control,  additional  cost savings  therefore  contribute
directly to profit.

The  previous  distribution  price  control  period  expired on March 31,  2000.
Changes to the formula  took effect  from April 1, 2000  resulting  in a one-off
reduction in allowed  income per unit  distributed of around 24%. As part of the
review, the Xd factor remains at 3%. The distribution prices allowable under the
current  distribution  price control  formula are expected to be reviewed by the
Office  of Gas  and  Electricity  Markets  ("Ofgem")  at the  expiration  of the
formula's  scheduled  five-year duration in 2005. The formula may be reviewed at
other  times at the  discretion  of  Ofgem,  including  in  connection  with the
proposed Information and Incentive Project (IIP) under which it is proposed that
2%  of  regulated   income  will  depend  upon  the  performance  of  the  PES's
distribution  system  as  measured  by  the  number  and  duration  of  customer
interruptions  and upon the  level of  customer  satisfaction  monitored  by the
regulator.

<PAGE>
Supply

In December 1999, Ofgem announced revised electric supply price controls.  Since
April  2000,  these have been  applied  to most  domestic  and small  commercial
customers in the below 100kW market of Northern's designated area, and result in
a further lowering of price caps. The new price control applies for two years to
March 2002.

While the impact of the latest regulatory  review varied across  companies,  the
impact on a standard  Northern  customer was a price reduction of  approximately
11%.

The supply  companies  are able to propose and amend the  detailed  structure of
tariffs,  but these must be submitted to Ofgem to ensure their  consistency with
the prescribed  price caps.  Prices are then monitored on an ongoing basis,  and
any proposed further amendments must be submitted to Ofgem for review.

In addition to the constraint of regulatory  price caps,  competitive  pressures
from other suppliers are exerted against Northern's  tariffs and contracts.  The
costs of fulfilling customer  requirements are also subject to market pressures,
with energy prices varying on a half hourly basis.  At present,  electric prices
are  established  on a national  half hourly basis  through the  electric  pool.
Northern principally employs contracts to hedge the risk contingent on movements
in pool price.

Beginning on March 27, 2001, the New Electricity Trading  Arrangements  ("NETA")
replaced the Pool with market arrangements more reflective of other commodities.
The bulk of energy settlement under this system should occur either  bilaterally
or  through  power  exchanges.  Risk  mitigation  should  be  dependent  on  the
establishment  of  effective  load  forecasting  tools,   addressing  short  and
longer-term  requirements.   In  addition,  it  is  expected  that  new  hedging
facilities  will  be  established,  although  the  form of  these  has yet to be
defined.

Environmental Matters:  Domestic

The U.S.  Environmental  Protection  Agency,  or 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 sufficient
concentrations as to warrant remedial action.

MidAmerican  Energy has evaluated or is evaluating 27 properties  which 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.  MidAmerican  Energy's estimate of the probable costs for these
sites as of December 31, 2000, was $24 million.  This estimate has been recorded
as a liability and a regulatory asset for future recovery through the regulatory
process.

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 or results of operations.

On July 18, 1997, the EPA adopted  revisions to the National Ambient Air Quality
Standards for ozone and a new standard for fine particulate patter. In May 1999,
the U.S.  Court of Appeals for the  District of Columbia  Circuit  remanded  the
standards  adopted  in July  1997  back to the  EPA  indicating  the EPA had not
expressed  sufficient  justification for the basis of establishing the standards
and ruling that the EPA has exceeded its constitutionally-delegated authority in
setting the  standards.  As a result of the  court's  initial  decision  and the
current status of the standards,  the impact of any new standards on the Company
is currently  unknown.  If the EPA  successfully  appeals the court's  decision,
however,  and the new standards are implemented,  then MidAmerican  Energy could
incur increased costs and a decrease in revenues.

<PAGE>
Environmental Matters:  U.K.

Northern  carries 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 been no  significant
environmental compliance issues.

The U.K.  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.

Northern is in the process of completing the evaluation  work on the seven sites
which may be subject to the  legislation.  A  compliance  strategy  will then be
developed.  Exploratory  work  with  an  environmental  remediation  company  is
expected to minimize any clean up costs.

The  Environmental  Protection  Act  (Disposal  of  PCB's  and  other  Dangerous
Substances)  Regulations  2000 were  introduced on May 5, 2000. The  regulations
required  that  transformers  containing  over 50  parts  per  million  (PPM) be
registered with the Environment Agency by July 31, 2000. Transformers containing
500 PPM must be  decontaminated by December 31, 2000. Northern has registered 62
items above 50 PPM,  decontaminated 4 items and informed the Environment Agency
that it is continuing with its sampling, labeling and registration program.

Nuclear Decommissioning

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 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,  the Company  expects to
contribute  approximately  $41 million during the period 2001 through 2005 to an
external trust established for the investment of funds for decommissioning  Quad
Cities  Station.  Approximately  60% 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 U.S. Treasury bonds.

In  addition,  during the year 2000,  MidAmerican  Energy  made  payments to the
Nebraska  Public  Power  District  ("NPPD")  related to  decommissioning  Cooper
Nuclear Station  ("Cooper")  based on an assumed shutdown of Cooper in September
2004.  These  payments are  reflected in operating  expense in the  consolidated
statements of  operations.  Based on NPPD  estimates  assuming a September  2004
shutdown  of Cooper,  MidAmerican  Energy  expects to accrue  approximately  $55
million for Cooper  decommissioning  during the period 2001  through  2004.  The
funds that have been provided to NPPD, with the  understanding  that Cooper will
be shut down in September  2004,  are invested  predominately  in U.S.  Treasury
Bonds and other U.S.  Government  securities.  Approximately 30% was invested in
domestic corporate debt.  MidAmerican  Energy's  obligation,  if any, for Cooper
decommissioning may be affected by the actual plant shutdown date. In July 1997,
NPPD  filed a lawsuit  in United  States  District  Court  for the  District  of
Nebraska naming MidAmerican Energy as the defendant and seeking a declaration of
MidAmerican  Energy's  rights and  obligations in connection with Cooper nuclear
decommissioning funding.

Cooper and Quad Cities Station  decommissioning  costs charged to Iowa customers
are included in base rates,  and recovery of increases in those  amounts must be
sought  through the normal  ratemaking  process.  Cooper  decommissioning  costs
charged to Illinois  customers  are  recovered  through a rate rider on customer
billings.

<PAGE>
Development Activity

The  Company is  actively  seeking to  develop,  construct,  own and operate 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 and sales  contracts  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.

The  financing,  construction  and  development  of projects  outside the United
States entail  significant  political and financial  risks  (including,  without
limitation,  uncertainties  associated with first time privatization  efforts in
the  countries   involved,   currency  exchange  rate   fluctuations,   currency
repatriation   restrictions,    political   instability,    civil   unrest   and
expropriation)  and other  structuring  issues that have the  potential to cause
substantial  delays or material  impairment  of the value of the  project  being
developed,  which the Company may not be fully capable of insuring against.  The
uncertainty of the legal  environment in certain foreign  countries in which the
Company may develop or acquire  projects  could make it more  difficult  for the
Company to enforce its rights under  agreements  relating to such  projects.  In
addition, the laws and regulations of certain countries may limit the ability of
the  Company to hold a majority  interest  in some of the  projects  that it may
develop or acquire. The Company's  international projects may, in certain cases,
be  terminated  by  a  government.  Projects  in  operation,   construction  and
development are subject to a number of uncertainties more specifically described
in the Company's Form 8-K,  dated March 26, 1999,  filed with the Securities and
Exchange Commission.

New Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial  Accounting  Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments  and  Hedging  Activities,"  which was  delayed  by SFAS No. 137 and
amended by SFAS No. 138. SFAS 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.  The Company  implemented
the new standards on January 1, 2001.  The initial  adoption of the SFAS 133/138
did not have a material impact on the Company's financial  position,  results of
operations or any impact on its cash flows.

The FASB's  Derivatives  Implementation  Group continues to identify and provide
guidance on various  implementation  issues  related to SFAS 133/138 that are in
varying stages of review and clearance by the Derivatives  Implementation  Group
and the FASB. The Company has not determined if the ultimate resolution of those
issues would have a material impact on its financial statements.

In September  2000, the FASB issued SFAS No. 140,  "Accounting for Transfers and
Servicing of Financial  Assets and  extinguishments  of Liabilities"  (FAS 140),
replacing  SFAS No. 125,  "Accounting  for  Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities" (SFAS 125). SFAS 140 revised criteria
for  accounting  for  securitizations,   other  financial  asset  transfers  and
collateral,  and  introduces new  disclosures.  SFAS 140 is effective for fiscal
2000 with  respect to the new  disclosure  requirements  and  amendments  of the
collateral provisions originally presented in SFAS 125. All other provisions are
effective for transfers of financial assets and  extinguishments  of liabilities
occurring  after March 31, 2001. The provisions are to be applied  prospectively
with certain  exceptions.  Management is currently assessing the impact that FAS
140 will have on the Company's consolidated financial statements.

<PAGE>
Qualitative and Quantitative Disclosures About Market Risk

The  following  discussion  of the  Company's  exposure to various  market risks
contains  "forward-looking  statements"  that involve  risks and  uncertainties.
These  projected  results  have  been  prepared  utilizing  certain  assumptions
considered reasonable in the circumstances and in light of information currently
available to the Company.  Actual  results  could differ  materially  from those
projected in the forward-looking information.

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.

Interest Rate Risk

At  December  31, 2000,  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  $6,548.7  million  in  principal  amount  and  having a fair value of
$6,400.1  million.  These instruments are fixed-rate and therefore do not expose
the  Company to the risk of  earnings  loss due to  changes  in market  interest
rates.   However,  the  fair  value  of  these  instruments  would  decrease  by
approximately  $234 million if interest rates were to increase by 10% from their
levels at December  31,  2000.  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,  2000,  the Company had  floating-rate  obligations  of $229.2
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, 2000
levels, the Company's  consolidated interest expense for unhedged  floating-rate
obligations  would increase by  approximately  $139,000 each month in which such
increase continued based upon December 31, 2000 principal balances.

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. As of December 31, 2000,  the market value of this
swap was $5.0 million.

Currency Exchange Rate Risk

At December 31, 2000, CE Electric UK Funding Company had fixed-rate  obligations
denominated in U.S. dollars that expose CE Electric UK Funding Company to losses
in the event of increases in the exchange rate of U.S.  dollars to Sterling.  CE
Electric UK Funding Company  entered into certain  currency rate swap agreements
that effectively  convert the U.S. dollar fixed interest rate to a fixed rate in
Sterling.  At December 31, 2000,  these  currency  rate swap  agreements  had an
aggregate  notional  amount of $362  million,  which the Company  would  receive
approximately  $23.1 million at  termination.  A decrease of 10% in the December
31, 2000 rate of exchange of  Sterling  to dollars  would  increase  the cost of
terminating these swap agreements by approximately $39.5 million.

<PAGE>
Energy Commodity Price Risk

Northern

Northern  utilizes  contracts for differences  ("CFDs"),  as part of the overall
risk management  strategy of its electricity  supply  business,  to mitigate its
exposure  to  volatility  in the  price of  electricity  purchased  through  the
electricity pool (the "Pool").

The portfolio of CFDs held for risk management  purposes is established to match
the notional quantity of the expected or committed transaction volumes that will
be subject to commodity  price risk over the same time period.  The portfolio is
therefore managed to complement the expected  electricity  purchase  transaction
portfolio,  thereby reducing  electricity price change risk to within acceptable
limits.

As a  consequence,  the value of the portfolio of CFDs,  which are held for risk
management  purposes,  is directly  linked to the  hypothetical  changes in Pool
price,  such  that an  adverse  movement  in Pool  price  would be  offset  by a
compensating impact on the contract. For the specified volumes,  therefore,  the
impact of Pool risk is constrained at a pre-determined level, assuming:

(i)      The CFD is not closed in advance of its agreed term.
(ii)     The level of  purchase  occurs as expected, matching volumes covered by
         the CFD.

Therefore,  disclosure  in respect  to CFDs  relies on the  assumption  that the
contracts exist in parallel to underlying actual electricity  purchases.  In the
absence of such  purchases the contract  would generate a loss or gain dependent
on the pool prices prevailing over the periods covered by the contract terms. As
of December 31, 2000,  the notional  amount of executed  CFDs was  approximately
$590.4  million,  representing  approximately  18% of the  expected or committed
transaction volumes through December 31, 2004. The fair value of these contracts
was a liability of  approximately  $30.5 million  discounted at 15%,  based upon
quoted market prices at December 31, 2000. A hypothetical decrease of 10% in the
market price of  electricity  from the  December  31, 2000 levels would  further
decrease  the fair value of these  contracts  by  approximately  $49.5  million.
However, as stated above, the value of the portfolio of CFDs, which are held for
risk management purposes, is directly linked to the hypothetical changes in Pool
price,  such that a  movement  in Pool price  would be offset by a  compensating
impact on the contract.

The current gas purchasing  strategy of Northern's gas supply business minimizes
risks in a rapidly  changing  market by buying  both medium and  short-term  gas
forward   contracts   directly   backing  sales  to  customers   within  prudent
anticipation of future demand growth.

The  portfolio  of contracts is varied so as to lock in price at an early stage.
This portfolio may take various forms including long-term daily swing contracts,
annual swing contracts and flat monthly or quarterly standard blocks.

Over time,  each month's  coverage is assessed as to the  likelihood of matching
demand and supply cover.  Any changes to the forecast are built into the forward
purchase requirements.  In addition, applying pricing scenarios to the uncovered
portion of the portfolio continuously assesses the supply risk to the business.

As of December 31, 2000,  the notional  amount of outstanding  forward  purchase
contracts was approximately  $201.0 million,  representing  approximately 10% of
expected  sales through  December 31, 2007. The fair value of such contracts was
an asset of  approximately  $60.2 million  discounted at 15%,  based upon quoted
market prices at December 31, 2000. A hypothetical decrease of 10% in the market
price of gas from the December 31, 2000 levels would  further  decrease the fair
value of these contracts by approximately $22.5 million.

<PAGE>
Northern had the following  financial  derivative  instruments  for its electric
operations as of December 31:


Derivative instruments used for other than trading purposes-
------------------------------------------------------------
                                                     2000              1999
                                               ---------------    --------------

Electricity Contracts for Differences:
         Net Contract Volumes - Long            17,081,000 MWh    14,981,000 MWh
         Unrealized Loss, in thousands          $30,543           $8,212

A $5.00  increase in underlying  electricity  prices would  decrease  unrealized
losses into an unrealized gain on the contract for differences  held at December
31, 2000 by approximately $85.4 million.

MidAmerican

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 losses 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
under  strict  value  at risk  guidelines  outlined  by  senior  management.  In
accordance  with the FASB's  Emerging Issues Task Force Abstract No. 98-10 (EITF
98-10),  derivative  instruments  held for trading purposes are recorded at fair
value and any  unrealized  gains or losses are reported in earnings.  EITF 98-10
has not had a material effect on the Company's  financial  position,  results of
operations or cash flows.

MidAmerican Energy uses electricity forward contracts to hedge anticipated sales
of wholesale electric power. Electric forward contracts are not reflected in the
financial statements until they are settled.

<PAGE>

MidAmerican Energy had the following  financial  derivative  instruments for its
natural gas and electric operations as of December 31:

Derivative instruments used for other than trading purposes-
------------------------------------------------------------

                                                2000                 1999
                                          ----------------     -----------------

Natural Gas Futures Contracts - NYMEX:
   Net Contract Volumes- Long (Short)      1,460,000 MMBtu      (500,000) MMBtu
   Unrealized Gain (Loss), in thousands       $7,554               $(410)


Natural Gas Swap Contracts:
   Contract Volumes                       24,106,980 MMBtu     85,520,442 MMBtu
   Unrealized Gain (Loss), in thousands       $8,055               $(1,576)

Natural Gas Options:
   Contract Volumes - Long                 1,790,280 MMBtu             -
   Unrealized Gain, in thousands                $953                   -

Electric Forward Contracts:
   Contract Volumes - (Short)              (139,200) MWh               -
   Unrealized (Loss), in thousands           $(4,731)                  -

A $1.00  increase in  underlying  natural gas prices would  increase  unrealized
gains on the futures  contracts held at December 31, 2000 by approximately  $1.5
million  and would  increase  unrealized  gains on the above swap  contracts  by
approximately  $2.3 million.  A $5.00 increase in underlying  electricity prices
would increase  unrealized  losses on the forward contracts held at December 31,
2000 by approximately $0.7 million.

Forward-looking Statements

Certain information included in this report contains forward-looking  statements
made pursuant to the Private  Securities  Litigation Reform Act of 1995 ("Reform
Act"). Such statements are based on current expectations and involve a number of
known and unknown risks and  uncertainties  that could cause the actual  results
and  performance of the Company to differ  materially  from any expected  future
results or performance, expressed or implied, by the forward-looking statements.
In connection with the safe harbor provisions of the Reform Act, the Company has
identified   important  factors  that  could  cause  actual  results  to  differ
materially from such expectations,  including development uncertainty, operating
uncertainty,  acquisition uncertainty,  uncertainties relating to doing business
outside of the United States,  uncertainties  relating to geothermal  resources,
the financial  condition of and relationships with customers and suppliers,  the
availability  and  price of fuel and other  inputs,  uncertainties  relating  to
domestic and international  economic and political  conditions and uncertainties
regarding  the impact of  regulations,  changes in government  policy,  industry
deregulation  and  competition.  Reference is made to all of the  Company's  SEC
filings,  including  the  Company's  Report  on Form 8-K dated  March 26,  1999,
incorporated herein by reference, for a description of such factors. The Company
assumes  no  responsibility  to  update  forward-looking  information  contained
herein.

<PAGE>
<TABLE>
                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                           CONSOLIDATED BALANCE SHEETS
                                 (In thousands)
<CAPTION>
                                                                                As of December 31,
                                                                           -------------------------------
                                                                                 2000            1999
                                                                           --------------    -------------
Assets
Current Assets:
<S>                                                                         <C>                 <C>
   Cash and investments................................................       $   38,152        $  316,327
   Restricted cash and short term investments..........................           42,129            36,294
   Accounts receivable.................................................          903,469           600,564
   Inventories.........................................................           81,943            94,981
   Other current assets................................................           96,784            90,147
                                                                              ----------        ----------
      Total Current Assets.............................................        1,162,477         1,138,313

Property, plant, contracts and equipment, net .........................        5,348,647         5,463,329
Excess of cost over fair value of net assets acquired, net.............        3,673,150         2,712,677
Regulatory assets......................................................          240,934           278,757
Long-term restricted cash and investments..............................           48,747           255,440
Nuclear decommissioning trust fund and other marketable securities.....          202,227           226,298
Equity investments.....................................................          246,466           208,023
Deferred charges, other investments and other assets...................          758,003           483,515
                                                                             -----------       -----------

   Total Assets........................................................      $11,680,651       $10,766,352
                                                                             ===========       ===========

Liabilities and Stockholders' Equity
Current Liabilities:
   Accounts payable....................................................    $     656,356      $    449,203
   Accrued interest....................................................          107,726            94,983
   Accrued taxes.......................................................          125,645           145,534
   Other accrued liabilities...........................................          250,975           218,150
   Short-term debt.....................................................          251,656           379,523
   Current portion of long-term debt...................................          438,978           235,202
                                                                             -----------        ----------
      Total Current Liabilities........................................        1,831,336         1,522,595

Other long-term accrued liabilities....................................          976,030         1,054,440
Parent company debt....................................................        1,829,971         1,856,318
Subsidiary and project debt............................................        3,398,696         3,642,703
Deferred income taxes..................................................          945,028           902,868
                                                                              ----------        ----------
   Total Liabilities...................................................        8,981,061         8,978,924
                                                                              ----------        ----------

Deferred income........................................................           79,489            65,509
Minority interest......................................................           11,491            29,127
Company-obligated mandatorily redeemable
   preferred securities of subsidiary trusts...........................          786,523           450,000
Subsidiary-obligated mandatorily redeemable
   preferred securities of subsidiary trusts  .........................          100,000           101,598
Preferred securities of subsidiaries...................................          145,686           146,606

Commitments and contingencies (Notes 4, 15, 17, 18 and 19)

Stockholders' Equity:
Zero coupon convertible preferred stock - authorized 50,000 shares,
    no par value, 34,563 shares outstanding at December 31, 2000.......                -                 -
Common stock - authorized 60,000 and 180,000 shares, no par value;
   9,281 and 82,980 shares issued, 9,281 and 59,944 shares outstanding,
   at December 31, 2000 and 1999, respectively.........................                -                 -
Additional paid in capital.............................................        1,553,073         1,249,079
Retained earnings......................................................           81,257           507,726
Accumulated other comprehensive loss, net..............................          (57,929)          (12,029)
Treasury stock - 23,036 common shares at December 31, 1999 at cost.....                -          (750,188)
                                                                             -----------       -----------
   Total Stockholders' Equity..........................................        1,576,401           994,588
                                                                             -----------       -----------

Total Liabilities and Stockholders' Equity.............................      $11,680,651       $10,766,352
                                                                             ===========       ===========
</TABLE>

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

<PAGE>
<TABLE>
                       MIDAMERICAN ENERGY HOLDINGS COMPANY

                      CONSOLIDATED STATEMENTS OF OPERATIONS

                                 (In thousands)
<CAPTION>
                                                                                              MEHC (Predecessor)
                                                                           -----------------------------------------------
                                                        March 14, 2000     January 1, 2000
                                                           through              through            Year Ended December 31,
                                                                                                   -----------------------
                                                     December 31, 2000    March 13, 2000           1999             1998
                                                     -----------------    --------------           ----             ----
<S>                                                      <C>                <C>                  <C>             <C>
Revenue:
   Operating revenue..............................       $3,945,716         $1,043,072           $4,128,737      $2,555,206
   Interest and other income......................           94,882             19,484              143,175         127,505
   Gains on non-recurring items...................                -                  -              138,704               -
                                                         ----------         ----------           ----------      ----------
Total revenues....................................        4,040,598          1,062,556            4,410,616       2,682,711
                                                         ----------         ----------           ----------      ----------

Costs and expenses:
   Cost of sales..................................        2,222,128            561,386            2,143,891       1,258,539
   Operating expense..............................          904,511            219,303            1,001,384         471,405
   Depreciation and amortization..................          383,351             97,278              427,690         333,422
   Interest expense...............................          396,773            101,330              496,578         406,084
   Less interest capitalized......................          (85,369)           (15,516)             (70,405)        (58,792)
   Losses on non-recurring items..................                -              7,605               54,409               -
                                                         ----------          ---------           ----------      ----------
Total costs and expenses..........................        3,821,394            971,386            4,053,547       2,410,658
                                                         ----------          ---------           ----------      ----------

Income before provision for income taxes..........          219,204             91,170              357,069         272,053
Provision for income taxes........................           53,277             31,008               93,475          93,265
                                                         ----------          ---------           ----------      ----------

Income before minority interest...................          165,927             60,162              263,594         178,788
Minority interest.................................           84,670              8,850               46,923          41,276
                                                         ----------          ---------           ----------      ----------
Income before extraordinary item and
   cumulative effect of change in accounting
   principle.....................................           81,257             51,312               216,671         137,512

Extraordinary item, net of tax....................               -                  -               (49,441)         (7,146)
Cumulative effect of change in accounting
   principle, net of tax..........................               -                  -                     -          (3,363)
                                                          -----------       ----------           ----------       ---------
Net income available to common
    stockholders..................................        $    81,257       $   51,312          $   167,230       $ 127,003
                                                          ===========       ==========          ===========       =========
</TABLE>
The accompanying notes are an integral part of these financial statements.

<PAGE>

                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                   For the Three Years Ended December 31, 2000
                                 (In thousands)
<TABLE>
<CAPTION>
                                                                         Accumulated
                                                                            Other   Additional
                                                                           Compre- Common Stock
                              Outstanding          Additional              hensive   & Options
                                Common      Common  Paid-In    Retained    Income   Subject to  Treasury
                                Shares       Stock  Capital    Earnings    (Loss)   Redemption    Stock        Total
                                ------       -----  -------    --------    ------   ----------    -----        -----
<S>                              <C>            <C><C>        <C>       <C>        <C>        <C>        <C>
Balance January 1, 1998          81,322$        - $1,266,683  $ 213,493 $  (3,589) $(654,736) $ (56,525) $   765,326

Net income                            -         -          -     127,003        -          -          -      127,003
Other Comprehensive Income:
   Foreign currency translation

      adjustment *                    -         -          -          -     3,634          -          -        3,634
                                                                                                            ---------
Comprehensive income                                                                                          130,637
Exercise of stock options and
   other equity transactions        226         -      (7,841)         -         -          -      7,825          (16)
Purchase of treasury stock      (21,943)        -     (21,313)         -         -          -   (703,478)    (724,791)
Common stock and options
   subject to redemption              -         -           -          -         -    654,736          -      654,736
Tax benefit from stock plan           -         -       1,161          -         -          -          -        1,161

----------------------------------------------------------------------------------------------------------------------
Balance December 31, 1998        59,605         -   1,238,690    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          -         -          -          -        9,113
Exercise of stock options and
   other equity transactions        238         -      (2,628)         -         -          -      7,779        5,151
Purchase of treasury stock       (3,376)        -           -          -         -          -   (104,847)    (104,847)
Conversion of TIDES I             3,477         -       2,845          -         -          -     99,058      101,903
Tax benefit from stock plan           -         -       1,059          -         -          -          -        1,059

----------------------------------------------------------------------------------------------------------------------
Balance December 31, 1999        59,944         -   1,249,079    507,726   (12,029)         -   (750,188)     994,588

Net income January 1, 2000            -         -           -     51,312         -          -          -       51,312
      through March 13, 2000
Net income March 14, 2000
   through December 31, 2000          -         -           -     81,257         -          -          -       81,257
Other Comprehensive Income:
   Foreign currency translation

      adjustment *                    -         -           -          -   (82,996)         -          -      (82,996)
   Unrealized losses on securities,
      net of tax of  $123             -         -           -          -      (228)         -          -         (228)
                                                                                                              -------
   Comprehensive income                                                                                        49,345
Exercise of stock options and
   other equity transactions         13         -        (138)         -         -          -        418          280
Teton Transaction               (50,676)        -     304,132   (559,038)   37,324          -    749,770      532,188

----------------------------------------------------------------------------------------------------------------------
Balance December 31, 2000         9,281  $      -  $1,553,073  $  81,257 $ (57,929)   $     -    $     -   $1,576,401

======================================================================================================================
     *  Foreign currency translation adjustment has no tax effect
The accompanying notes are an integral part of these financial statements
</TABLE>
<PAGE>
<TABLE>

                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (In thousands)
<CAPTION>
                                                                                             MEHC (Predecessor)
                                                                           ---------------------------------------------
                                                      March 14, 2000     January 1, 2000
                                                         through              through             Year Ended December 31,
                                                                                                 -----------------------
                                                     December 31, 2000    March 13, 2000           1999           1998
                                                     -----------------    --------------           ----           ----
<S>                                                       <C>              <C>                <C>           <C>
Cash flows from operating activities:

Net income...........................................     $    81,257      $    51,312        $   167,230     $  127,003
Adjustments to reconcile net cash flows from
  operating activities:
   Gains on non-recurring items......................               -                -           (138,704)             -
   Extraordinary item, net of tax....................               -                -             49,441          7,146
   Cumulative effect of change in accounting principle              -                -                  -          3,363
   Depreciation and amortization.....................         310,418           83,194            363,737        290,794
   Amortization of excess of cost over fair value of net
     assets acquired.................................          72,933           14,084             63,953         42,628
   Amortization of deferred financing and other costs          17,402            4,334             18,181         21,723
   Provision for deferred income taxes...............         (15,460)           7,735            (56,590)        34,332
   Distributions in excess of (less than) income on
     equity investments..............................         (26,607)          (3,459)           (22,796)         6,171
   Changes in other items:
     Accounts receivable and other current assets....        (360,710)          46,436             61,209       (135,124)
     Accounts payable, accrued liabilities,  deferred
     income and other................................          71,474           63,447             47,157        (36,490)
                                                           ----------        ---------         ----------     ----------
Net cash flows from operating activities.............         150,707          267,083            552,818        361,546
                                                           ----------        ---------         ----------     ----------

Cash flows from investing activities:
Purchase of MEHC (Predecessor), MidAmerican, and
    Kiewit's Interests, net of cash acquired.........     (2,048,266)                -         (2,501,425)      (500,916)
Proceeds from sale of qualified facilities, net of cash
     disposed........................................               -                -            365,074              -
Proceeds from Indonesia settlement...................               -                -            290,000              -
Purchase of marketable securities....................         (44,686)          (8,251)           (92,523)             -
Proceeds from sale of marketable securities..........          72,225           10,665            498,676              -
Capital expenditures relating to operating projects..        (174,361)         (21,685)          (331,337)      (227,071)
Philippine construction..............................         (58,531)         (22,736)           (62,059)      (112,263)
Acquisition of U.K. gas assets.......................               -                -            (72,280)       (35,677)
Construction and other development costs.............        (176,323)         (56,720)          (180,683)      (119,916)
Decrease in restricted cash and investments..........         158,049           42,809            199,588         20,568
Other................................................          38,971          (74,765)           (58,263)       (32,505)
                                                           ----------        ---------         ----------     ----------
Net cash flows from investing activities.............      (2,232,922)        (130,683)        (1,945,232)    (1,007,780)
                                                           ----------        ---------         ----------     ----------

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                -                  -              -
Proceeds from issuance of parent company debt........               -                -                  -      1,502,243
Repayments of parent company debt....................          (4,225)               -           (853,420)      (167,285)
Net proceeds from revolver...........................          85,000                -                  -              -
Proceeds from subsidiary and project debt............         256,133            6,043          1,429,856        464,974
Repayments of subsidiary and project debt............        (317,553)        (133,060)          (369,016)      (255,711)
Deferred charges relating to debt financing..........          (4,292)               -              7,761        (47,205)
Redemption of preferred securities of subsidiaries...         (20,415)               -                  -              -
Purchase of treasury stock...........................               -                -           (104,847)      (724,791)
Other................................................             358             (149)             4,306         25,113
                                                          -----------       -----------       -----------    -----------
Net cash flows from financing activities.............       1,877,802         (127,166)           114,640        797,338
                                                          -----------       -----------       -----------    -----------
Effect of exchange rate changes......................         (61,046)         (21,950)           (12,047)         3,634
                                                          -----------       -----------       -----------    -----------
Net increase (decrease) in cash and cash equivalents.        (265,459)         (12,716)        (1,289,821)       154,738
Cash and cash equivalents at beginning of period.....         303,611          316,327          1,606,148      1,451,410
                                                          -----------       ----------        -----------    -----------
Cash and cash equivalents at end of period...........     $    38,152       $  303,611        $   316,327    $ 1,606,148
                                                          ===========       ==========        ===========    ===========
Supplemental Disclosures:
Interest paid, net of amount capitalized.............     $   351,532       $   35,057        $   439,894    $   341,645
                                                          ===========       ==========        ===========    ===========
Income taxes paid....................................     $    94,405       $        -        $   130,875    $    53,609
                                                          ===========       ==========        ===========    ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.

<PAGE>

                       MidAmerican Energy Holdings Company
                   Notes To Consolidated Financial Statements

1.  Business

MidAmerican  Energy Holdings Company  (successor to MidAmerican  Energy Holdings
Company  (Predecessor),  referred to as "MEHC  (Predecessor)")  and subsidiaries
(collectively  referred to as the "Company" or "MEHC"), is a United States-based
privately  owned  global  energy  company  with  publicly  traded  fixed  income
securities  which  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 four
separate   platforms:   MidAmerican,    Northern,   CalEnergy   Generation   and
HomeServices.

MidAmerican

The  MidAmerican  Platform  consists  primarily  of the  Company's  ownership in
MidAmerican  Energy Company  ("MidAmerican  Energy").  MidAmerican Energy is the
largest energy company  headquartered  in Iowa and 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 retail in Iowa,
Illinois,  and South Dakota. It also distributes  natural gas at retail in Iowa,
Illinois, South Dakota and Nebraska. As of December 31, 2000, MidAmerican Energy
had 669,000 retail electric customers and 647,000 retail natural gas customers.

In addition to retail sales,  MidAmerican  Energy sells electric energy to other
utilities,  marketers and municipalities who 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.

Northern

The operations of Northern Electric plc  ("Northern"),  an indirect wholly owned
subsidiary of the Company,  consist  primarily of the distribution and supply of
electricity,  supply of natural gas and other auxiliary businesses in the United
Kingdom.

Northern  receives  electricity from the national grid  transmission  system and
distributes  it to  customers'  premises  using  its  network  of  transformers,
switchgear  and  cables.  Substantially  all  of  the  customers  in  Northern's
authorized  area are connected to  Northern's  network and can only be delivered
electricity through Northern's distribution system,  regardless of whether it is
supplied by Northern's own supply business or by other suppliers, thus providing
Northern  with  distribution  volume that is stable from year to year.  Northern
charges  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.

Northern's supply business  primarily involves the bulk purchase of electricity,
through a central  pool,  and  subsequent  resale to individual  customers.  The
supply  business  generally is a high volume  business  that tends to operate at
lower profitability  levels than the distribution  business.  As of December 31,
2000, Northern supplied electricity to approximately 1.1 million customers.

Northern also competes to supply gas inside and outside its authorized  area. In
the residential market Northern currently supplies gas to approximately  470,000
customers.

<PAGE>
CalEnergy Generation

The CalEnergy Platform is engaged in the development, ownership and operation of
environmentally  responsible  independent power production  facilities worldwide
utilizing  geothermal,  natural gas,  hydroelectric  and other  energy  sources.
Through the Company's 50% owned subsidiary, CE Generation LLC ("CE Generation"),
the Company has interests in ten operating geothermal plants in Imperial Valley,
California  and three  operating  natural gas fired  cogeneration  plants in New
York, Texas and Arizona. The Company accounts for CE Generation under the equity
method.

The Company also  indirectly  owns the Upper  Mahiao,  Malitbog and  Mahanagdong
Projects (collectively,  the "Philippine Projects"),  which are geothermal power
plants located on the island of Leyte in the Philippines. Plant capacity amounts
for the Upper Mahiao, Malitbog and Mahanagdong Projects are 119, 216 and 165 net
MW, respectively.

HomeServices

The Company owns approximately 83% of HomeServices.Com,  Inc.  ("HomeServices"),
the second largest  residential  real estate brokerage firm in the United States
based on aggregate closed  transaction  sides in 1999 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 primarily
under the Edina Realty, Iowa Realty,  J.C. Nichols  Residential,  CBSHOME,  Paul
Semonin  Realtors,  Long Realty and Champion Realty brand names in the following
twelve states: Minnesota, Iowa, Arizona, Kansas, Missouri,  Kentucky,  Nebraska,
Wisconsin,  Indiana,  Maryland,  North  Dakota  and South  Dakota.  HomeServices
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, 1999.  HomeServices'  major markets  consist of the  following  metropolitan
areas:  Minneapolis and St. Paul, Minnesota;  Des Moines, Iowa; Omaha, Nebraska;
Kansas  City,  Kansas;  Louisville,  Kentucky;  Springfield,  Missouri;  Tucson,
Arizona and Annapolis, Maryland.

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.

Beginning March 14, 2000, the financial statements reflect the Teton Transaction
(described  in Note 3) and  the  resulting  push  down  of the  accounting  as a
purchase business combination.

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.

<PAGE>
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.

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  17 for  additional  information
regarding decommissioning costs.

Well, Resource Development and Exploration Costs

The Company  follows the full cost method of  accounting  for costs  incurred in
connection  with the  exploration  and development of geothermal and natural gas
resources. All such costs, which include dry hole costs and the cost of drilling
and equipping  production  wells and directly  attributable  administrative  and
interest costs,  are capitalized and amortized over their estimated useful lives
when production  commences.  The estimated useful lives of geothermal production
wells are ten to twenty years depending on the characteristics of the underlying
resource;  exploration costs and development costs, other than production wells,
are  generally  amortized  over  the  weighted  average  remaining  term  of the
Company's power and steam purchase contracts.

<PAGE>
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 40 year period for
the Teton and MidAmerican acquisitions, and a 32 year period for the acquisition
of Kiewit's interests.

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 models, whenever evidence
exists that the carrying value is not recoverable.

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.

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.

Deferred Income Taxes

The  Company  recognizes  deferred  tax  assets  and  liabilities  based  on the
difference  between  the  financial  statement  and  tax  bases  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  utilizes swap  agreements,  contracts for  differences  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.  For contracts for differences,  the net cash amounts paid or
received on the  agreements  are accrued and recognized as an adjustment to cost
of sales.  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.

<PAGE>
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 1999 and 1998  consolidated  financial  statements
and supporting note disclosures have been  reclassified to conform to the fiscal
2000 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"). Other accrued liabilities
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 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 the remaining Cooper capital  improvement  costs to expense as incurred
in January 1997.

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.

New Accounting Pronouncements

On January 1, 2001,  the  Company  adopted  Statement  of  Financial  Accounting
Standards  Nos. 133 and 138 (SFAS  133/138)  pertaining  to the  accounting  for
derivative  instruments and hedging activities.  SFAS 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  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 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 133.  Initial  adoption of SFAS
133/138  did not have a material  impact on the  results of  operations  for the
Company.

<PAGE>
The FASB's  Derivatives  Implementation  Group continues to identify and provide
guidance on various  implementation  issues  related to SFAS 133/138 that are in
varying stages of review and clearance by the Derivatives  Implementation  Group
and the FASB. The Company has not determined if the ultimate resolution of those
issues would have a material impact on its financial statements.

In September  2000, the FASB issued SFAS No. 140,  "Accounting for Transfers and
Servicing of Financial Assets and  extinguishments  of Liabilities"  (SFAS 140),
replacing  SFAS No. 125,  "Accounting  for  Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities" (SFAS 125). SFAS 140 revised criteria
for  accounting  for  securitizations,   other  financial  asset  transfers  and
collateral,  and  introduces new  disclosures.  SFAS 140 is effective for fiscal
2000 with  respect to the new  disclosure  requirements  and  amendments  of the
collateral provisions originally presented in SFAS 125. All other provisions are
effective for transfers of financial assets and  extinguishments  of liabilities
occurring  after March 31, 2001. The provisions are to be applied  prospectively
with certain exceptions.  Management is currently assessing the impact that SFAS
140 will have on the Company's consolidated financial statements.

3. Acquisitions/Dispositions

Teton Transaction

On October 24, 1999,  the Company and entities  representing  an investor  group
comprised of Berkshire Hathaway Inc. ("Berkshire Hathaway"),  Walter Scott, Jr.,
a director of the  Company,  and David L. Sokol,  Chairman  and Chief  Executive
Officer of the  Company,  executed  a  definitive  agreement  and plan of merger
whereby the investor 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. The 11% trust preferred securities have
a liquidation  preference of $25 each and are subject to mandatory redemption in
ten equal semi-annual  installments commencing December 15, 2005. 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
based on preliminary  valuations.  The final  purchase price  allocation has not
been completed;  however,  the Company does not anticipate any material  changes
based on  currently  available  information.  The Company  recorded  goodwill of
approximately  $1,242 million that is being  amortized  using the  straight-line
method over a 40-year period.

Unaudited pro forma combined revenue,  income before extraordinary items and net
income of the Company and MEHC  (Predecessor)  for the years ended  December 31,
2000 and 1999,  as if the Teton  Transaction  and the  MidAmerican  Merger  (see
below) 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,   were  $5,103.2   million,   $124.9  million  and  $124.9  million,
respectively,  compared to $4,801.1 million,  $187.7 million and $138.3 million,
respectively.

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.

<PAGE>
MidAmerican Merger

On August 11, 1998,  the Company  entered  into an Agreement  and Plan of Merger
with MHC  Inc.,  formerly  MidAmerican  Energy  Holdings  Company  ("MHC").  The
MidAmerican  Merger closed on March 12, 1999 and the Company paid $27.15 in cash
for each  outstanding  share of MHC  common  stock for a total of  approximately
$2.42 billion in a merger, pursuant to which MHC became an indirect wholly owned
subsidiary of the Company. Additionally, the Company reincorporated in the State
of Iowa,  was renamed  MidAmerican  Energy  Holdings  Company and, upon closing,
became an exempt public utility holding company.

The MidAmerican Merger has been accounted for as a purchase business combination
and as such the results of operations of the Company  include the results of MHC
beginning  March 12,  1999.  The  purchase  price has been  allocated  to assets
acquired and liabilities assumed. The Company recorded goodwill of approximately
$1.5 billion,  which is being  amortized using the  straight-line  method over a
40-year period.

Qualified Facilities Dispositions

The  consummation  of the MidAmerican  Merger was conditioned  upon receipt of a
number of regulatory approvals.  Regulatory approval required the disposition of
partial  interests  in certain of the  Company's  independent  power  generating
facilities  prior to the  consummation  of the  MidAmerican  Merger  in order to
maintain the qualifying  facilities status of such power generating  facilities.
To  accomplish  this  disposition,  the following  events  occurred in the first
quarter of 1999:

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 February 8, 1999,  the Company  created a new  subsidiary,  CE Generation LLC
("CE  Generation")  and  subsequently  transferred its interest in the Company's
power generation assets in the Imperial Valley Projects and the Gas Plants to CE
Generation.  On March 2, 1999,  CE  Generation  closed the sale of $400  million
aggregate  principal  amount of its 7.416% Senior  Secured Bonds due in 2018 and
distributed the proceeds to the Company.

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.  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 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.

HomeServices.Com

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%. The
Company  recognized a pre-tax gain on the sale of its HomeServices stock of $7.9
million,  which is reported in interest and other income. The Company recognized
a gain for  HomeServices'  sale of newly  issued stock of $9.1  million,  net of
deferred tax of $0.8 million,  which was recorded as a credit to additional paid
in capital.

<PAGE>
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%.

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  with  Perusahaan  Petambangan  Minyak Dan Gas Gumi
Negara ("Pertamina"), the Indonesian national oil company, and executed separate
"take-or-pay"  energy sales contracts  ("ESCs") with both Pertamina and P.T. PLN
(Persero) ("PLN"),  the Indonesian national electric utility.  The Government of
Indonesia provided sovereign  performance  undertakings of the obligations under
the joint operating and "take-or-pay"  contracts.  The Company carried political
risk  insurance on its  investment  in HCE and PPL through the Overseas  Private
Investment  Corporation ("OPIC"),  an agency of the U.S. Government,  as well as
through private market insurers.

In 1997 and 1998 a series of  Indonesian  government  decrees and other  actions
(including  the  non-payment  of all monthly  invoices  from HCE's Dieng Unit I,
which became  operational in March 1998) created  significant  uncertainty as to
whether  PLN  and  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.

On or about August 14, 1998, the Company,  through the Indonesian  Subsidiaries,
began arbitration proceedings against PLN in connection with the HCE's and PPL's
geothermal  power  projects  in  Indonesia,  the Dieng  Project  and the  Patuha
Project.  An  arbitral  tribunal  found  that PLN had  materially  breached  the
provisions  of the  ESCs  between  PLN and both HCE and  PPL,  and  awarded  HCE
approximately  $391.7  million  and PPL $180.6  million,  and ordered PLN to pay
these amounts immediately.

Following  PLN's  failure  to pay such  amounts,  HCE and PPL  demanded  payment
pursuant to the  sovereign  performance  undertakings  issued by the Minister of
Finance on behalf of the Republic of Indonesia ("ROI") and,  following the ROI's
failure  to pay,  brought  an  arbitration  against  the ROI for breach of those
undertakings.  A final award was issued by an international arbitration panel in
the ROI  arbitration  on October  15,  1999 that  found that the ROI  materially
breached its performance  undertakings and violated  international  law, and the
ROI was required to pay HCE and PPL an aggregate  amount of  approximately  $575
million.

Following  ROI's failure to pay such amount,  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.

<PAGE>
4. Property, Plant, Contracts and Equipment, Net:

Property, plant, contracts and equipment, net comprise the following at December
31 (in thousands):
                                                                        MEHC
                                                                   (Predecessor)
                                                           2000         1999
                                                        ----------   ----------
Operating assets:
Utility generation and distribution system...........   $6,266,391   $6,362,975
Independent power plants ............................      740,631      705,346
Wells and resource development.......................       47,916      123,845
Power sales agreements...............................       82,231            -
Other assets.........................................      387,709      377,897
                                                        ----------   ----------
Total operating assets...............................    7,524,878    7,570,063
Less accumulated depreciation and amortization.......   (3,332,098)  (3,062,387)
                                                        ----------   ----------
Net operating assets.................................    4,192,780    4,507,676
Mineral and gas reserves and exploration assets, net.      378,494      476,416
Construction in progress:
     Casecnan........................................      387,274      306,007
     Zinc recovery project...........................      165,585       92,794
     Cordova.........................................      224,514       79,982
     Other...........................................            -          454
                                                        -----------  ----------

Total                                                    $5,348,647  $5,463,329
                                                         ==========  ==========

Minerals Extraction

The  Company  developed  and 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 as well as the production of power
to be used in the extraction  process.  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  that  will  recover  zinc  from  the
geothermal  brine (the "Zinc Recovery  Project").  Facilities  will be installed
near the Imperial Valley Projects 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 operation in mid-2001.  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  is  being   constructed  by  Kvaerner  U.S.  Inc.
("Kvaerner")  pursuant  to a date  certain,  fixed-price,  turnkey  engineering,
procurement  and   construction   contract  (the  "Zinc  Recovery   Project  EPC
Contract").  Kvaerner is a wholly owned indirect  subsidiary of Kvaerner ASA, an
international  engineering  and  construction  firm  experienced  in the metals,
mining and  processing  industries.  Total  project  costs of the Zinc  Recovery
Project are expected to be approximately $200.9 million.

Casecnan

CE Casecnan  Water and Energy  Company,  Inc.,  a  Philippine  corporation  ("CE
Casecnan")  which at  completion  of the  Casecnan  Project is expected to be at
least 70% indirectly owned by the Company, is constructing the Casecnan Project,
a combined irrigation and 150 net MW hydroelectric power generation project (the
"Casecnan  Project")  located in the central  part of the island of Luzon in the
Republic of the Philippines.

<PAGE>
CE Casecnan has entered into a fixed-price,  date certain,  turnkey engineering,
procurement  and  construction  contract to  complete  the  construction  of the
Casecnan  Project (the  "Casecnan  Construction  Contract").  The work under the
Casecnan  Construction 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 Casecnan  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 lender's 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.
Accordingly,  the Casecnan Project is now expected to become  operational by the
third quarter of 2001.  The delay in completion is  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.

The receipt of the working  schedule does not change the Guaranteed  Substantial
Completion  Date under the  Replacement  Contract,  and the  Contractor is still
contractually  obligated  either to complete the  Casecnan  Project by March 31,
2001 or to pay delay liquidated  damages.  As a result of receipt of the working
schedule,  however,  CE  Casecnan  has 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, the 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 (the
"Shareholder  Support  Letter") to cover  additional  costs  resulting  from the
Contractor's schedule delay.

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,  2001resulting
from various force majeure events. In a March 20, 2001 Supplement to Request for
Arbitration, the Contractor also seeks compensation for alleged additional costs
it incurred from the claimed force majeure  events to the extent it is unable to
recover from its insurer.  CE Casecnan  believes  such  allegations  are without
merit and intends to vigorously defend the Contractor's claims.

Cordova

Cordova  Energy  Company  LLC  ("Cordova  Energy"),  an  indirect  wholly  owned
subsidiary  of the Company,  has  commenced  construction  of a 537 MW gas-fired
power plant in the Quad Cities,  Illinois area (the "Cordova Project").  Cordova
Energy has entered into an engineering,  procurement and  construction  contract
with Stone & Webster Engineering  Corporation ("SWEC") to build the project. The
construction  of the Cordova  Project is expected to be  completed  in mid-2001.
Total project costs are estimated to be approximately $288.9 million.

Cordova  Energy has entered into a power sales  agreement with a unit of El Paso
Energy  Corporation ("El Paso").  Under the power sales agreement,  El Paso will
purchase all the capacity and energy from the project  until  December 31, 2019.
However,  Cordova Energy has the option to elect on an annual basis to retain up
to 50% of the project capacity and energy for sales to others.

<PAGE>
5. Equity Investments

CE  Generation,  the  Company's  50%  owned  subsidiary,  has  interests  in ten
operating  geothermal plants in Imperial Valley,  California and three operating
natural gas-fired cogeneration plants in New York, Texas and Arizona. 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 following is
summarized financial information for CE Generation as of and for the years ended
December 31 (in thousands):

                                                       2000             1999
                                                       ----             ----

Current assets                                       $191,112         $119,829
Total assets                                        1,987,323        1,725,419
Current liabilities                                   138,751           92,842
Total liabilities                                   1,479,944        1,333,139
Revenues                                              510,796          340,683
Income before extraordinary item                       73,535           61,970
Net income                                             73,535           44,492

6. Short-Term Debt

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

                                                              MEHC (Predecessor)
                                                      2000              1999
                                                    --------          --------
Revolving credit facilities...................      $ 85,000          $      -
Northern treasury loan and other .............        85,056           175,523
MidAmerican Energy commercial paper...........        81,600           204,000
                                                    --------          ---------
                                                    $251,656          $379,523
                                                    ========          ========

Revolving Credit Facilities

The Company has available $400 million in revolving credit  facilities  expiring
in June 2001 and June 2003.  The  facilities  are unsecured and are available to
fund  working  capital   requirements  and  finance  future  business  expansion
opportunities.  As of December 31, 2000 there was an outstanding  balance of $85
million under these revolving credit facilities. The facility carries a variable
interest rate based on LIBOR and ranging from 6.6875% to 9.5% in 2000  (weighted
average interest rate of 8.16% at December 31, 2000).

MidAmerican Energy Commercial Paper

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  $400 million.  As of December 31, 2000,  MidAmerican  Energy had in
place a $370.4 million revolving credit facility which 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, 2000,  commercial paper and bank notes totaled $81.6 million for
MidAmerican Energy with a weighted average interest rate of 6.6%.

Northern Short Term Treasury Loan

Northern  had  short-term  money  market loans in place at December 31, 2000 and
1999 of $85.1 million and $174.6 million, respectively. The amounts have varying
maturities generally less than one month and carry variable interest rates based
on LIBOR and ranging from 4.95% to 6.41% at December 31, 2000.

<PAGE>
7. Parent Company Debt

Parent company debt comprises the following at December 31 (in thousands):

                                                              MEHC (Predecessor)
                                                        2000            1999
                                                     ----------      -----------
   9.5% Senior Notes.........................        $      32       $       32
   7.63% Senior Notes........................          350,000          350,000
   Limited Recourse Senior Secured Notes.....                 -           4,225
   $1.4 Billion Senior Notes ................         1,400,000       1,400,000
   $100 Million Senior Notes.................           101,888         102,061
   Fair Value Adjustment (see Note 3)........           (21,949)              -
                                                     ----------      -----------
                                                     $1,829,971      $1,856,318

9.5% Senior Notes

On September 20, 1996, the Company issued $225 million of 9.5% Senior Notes (the
"9.5% Senior  Notes") due in 2006.  Interest on the 9.5% Senior Notes is payable
semiannually  on March 15 and  September 15 of each year,  commencing  March 15,
1997. The 9.5% Senior Notes are redeemable at any time on or after September 15,
2001 initially at a redemption  price of 104.75%  declining to 100% on September
15, 2004 plus  accrued  interest to the date of  redemption.  During  1999,  the
Company  repurchased  and retired  substantially  all of the notes at an average
price of 110.055% plus accrued interest. Due to the early extinguishments of the
9.5% Senior Notes, the Company  recorded an extraordinary  loss in 1999 of $17.9
million,  net of tax. The 9.5% Senior Notes are unsecured senior  obligations of
the Company.

7.63% Senior Notes

On October 28, 1997,  the Company issued $350 million of 7.63% Senior Notes (the
"7.63% Senior Notes") due in 2007. Interest on the 7.63% Senior Notes is payable
semiannually on April 15 and October 15 of each year, commencing April 15, 1998.
The 7.63% Senior Notes are unsecured senior obligations of the Company.

Limited Recourse Senior Secured Notes

On July 21, 1995,  the Company  issued $200  million of 9 7/8% Limited  Recourse
Senior Secured Notes due in 2003 (the "Limited Recourse Notes"). Interest on the
Limited  Recourse  Notes was  payable on June 30 and  December  30 of each year,
commencing December 1995.

On  January  29,  1999,  the  Company  commenced  a cash  offer  for  all of its
outstanding Limited Recourse Notes. The Company received tenders from holders of
an aggregate of  approximately  $195.8  million of principal  which were paid on
March 3, 1999 at a redemption  price of 110.025% plus accrued  interest.  Due to
early  extinguishments  of the Limited  Recourse Notes,  the Company recorded an
extraordinary  loss of $17.5 million,  net of tax. On June 30, 2000, the Company
redeemed the remaining  $4.2 million of Limited  Recourse  Notes at a redemption
price of 104.9375% plus accrued interest.

$1.4 Billion Senior Notes

On September 22, 1998, the Company issued $215 million of 6.96% Senior Notes due
in 2003,  $260 million of 7.23% Senior Notes due in 2005,  $450 million of 7.52%
Senior  Notes due in 2008,  and $475  million of 8.48%  Senior Bonds due in 2028
(collectively,  the "$1.4 Billion Senior  Notes").  Interest on the $1.4 Billion
Senior Notes is payable  semiannually on March 15 and September 15 of each year,
commencing  March 15, 1999. The $1.4 Billion  Senior Notes are unsecured  senior
obligations of the Company.

<PAGE>
$100 Million Senior Notes

On  November  13,  1998,  the  Company  issued  $100  million  at a  premium  of
approximately  102.243% of 7.52% Senior Notes (the "$100 Million  Senior Notes")
due in 2008.  Interest on the $100 Million Senior Notes is payable  semiannually
on March 15 and September 15 of each year,  commencing  March 15, 1999. The $100
Million Senior Notes are unsecured senior obligations of the Company.

8.  Subsidiary and Project Debt

Project  loans held by  subsidiaries  and  projects  comprise  the  following at
December 31 (in thousands):

                                                              MEHC (Predecessor)
                                                      2000              1999
                                                  ------------       -----------
MidAmerican Funding, LLC Senior Notes and Bonds   $   702,287        $  702,089
MidAmerican Energy Mortgage Bonds                     340,570           450,570
MidAmerican Energy Pollution Control Bonds            158,625           159,129
MidAmerican Energy Notes                              422,240           260,240
MidAmerican Capital Notes                              46,667            70,098
HomeServices Senior Notes and Revolving Debt           47,607            48,817
Salton Sea Bonds                                      140,528           140,528
Northern Eurobonds                                    299,580           324,850
CE Electric UK Funding Company Senior Notes
   and Sterling Bonds                                 653,750           670,327
Casecnan Notes and Bonds                              346,439           363,085
Philippine Term Loans                                 392,625           449,739
Cordova Funding Senior Secured Bonds                  225,000           124,824
CE Gas Loan                                            73,162           113,267
Other                                                     239               342
Fair Value Adjustment (see Note 3)                    (11,645)                -
                                                   -----------       ----------
                                                   $3,837,674        $3,877,905
                                                   ==========        ==========

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   Northern,   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.

<PAGE>
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 Merger.

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):
                                                             MEHC (Predecessor)
                                                         2000           1999
                                                         ----           ----
Mortgage bonds:
    6% Series, due 2000..........................    $      -     $   35,000
    6.75% Series, due 2000.......................           -         75,000
    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       $450,570
                                                     ========       ========
Pollution control revenue obligations:
    5.75% Series, due periodically through 2003..    $  7,200       $  7,704
    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, 3.95% .................      37,600         37,600
       Due 2023 (secured by general mortgage
       bond, 3.95%)..............................      28,295         28,295
       Due 2023, 3.95%...........................       6,850          6,850
       Due 2024, 3.95%...........................      34,900         34,900
       Due 2025, 3.95%...........................      12,750         12,750
                                                     --------       --------
                                                     $158,625       $159,129
                                                     ========       ========
Notes:
    8.75% Series, due 2002.......................    $    240       $    240
    7.375% Series, due 2002......................     162,000              -
    6.5% Series, due 2001........................     100,000         100,000
    6.375% Series, due 2006......................     160,000         160,000
                                                     --------        --------
                                                     $422,240        $260,240
                                                     ========        ========

MidAmerican Capital Notes

MidAmerican Capital Company, a wholly owned subsidiary of the Company,  has debt
of $46.7 million of 8.52% Senior Notes. These notes are due in annual increments
of $23.3 million in 2001 and 2002.

HomeServices Senior Notes and Revolving Debt

HomeServices  debt  includes  $35  million of 7.12%  Senior  Notes due in annual
increments  of $5 million  beginning in 2004.  HomeServices  also obtained a $65
million senior secured revolving credit facility of which HomeServices had drawn
down  approximately  $10 million as of December 31, 2000. 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,  2000,  the
blended average  interest rate on the senior secured  revolving  credit facility
borrowings was 7.91%.

Salton Sea Bonds

CalEnergy  Minerals LLC, is one of several  guarantors of the Salton Sea Funding
Corporation's debt, which had a balance as of December 31, 2000 of approximately
$543.9 million. As a result of a note allocation  agreement,  CalEnergy Minerals
LLC is primarily  responsible  for $140.5  million of the 7.475% Senior  Secured
Series F Bonds due  November 30,  2018.  The Company has  guaranteed a specified
portion  of the  scheduled  debt  service  on the  Series F Bonds  equal to this
current principal amount of $140.5 million and associated interest.

<PAGE>
Northern Eurobonds

The  balance  at  December  31,  2000 and 1999  consists  of the  following  (in
thousands):

                                                              MEHC (Predecessor)
                                                   2000                   1999
                                                 --------              --------
8.625% Bearer bonds due 2005                     $149,865              $162,512
8.875% Bearer bonds due 2020                      149,715               162,338
                                                 --------              --------
                                                 $299,580              $324,850
                                                 ========              ========

CE Electric UK Funding Company Senior Notes and Sterling Bonds

On December 15, 1997, CE Electric UK Funding Company,  an indirect subsidiary of
the Company (the "CE Electric UK Funding Company"),  issued the Senior Notes and
Sterling  Bonds.  The balances at December 31 are comprised of the following (in
thousands):

                                                              MEHC (Predecessor)
                                                  2000                  1999
                                                --------              ---------
6.853% Senior Notes due 2004                    $124,503              $ 121,754
6.995% Senior Notes due 2007                     235,804                230,662
7.25% Sterling Bonds due 2022                    293,443                317,911
                                                --------               --------
                                                $653,750               $670,327
                                                ========               ========

The CE Electric UK Funding  Company  Senior  Notes and Sterling  Bonds  prohibit
distributions to any of its shareholders unless certain financial ratios are met
by the CE Electric UK Funding Company or the long-term debt rating falls below a
prescribed level.

CE  Electric  UK  Funding  Company  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, 2000 is approximately $23.1 million based on quotes from the counterparty to
these  instruments  and represents  the estimated  amount that the Company would
expect to receive when these agreements terminate. It is the Company's intention
to hold these swap agreements to maturity.

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. These consist of the following
(in thousands):

                                                              MEHC (Predecessor)
                                                            2000          1999
                                                          ---------     --------
Senior Secured Floating Rate Notes (FRNs) due in 2002     $ 49,939      $ 66,585
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
                                                          --------      --------
                                                          $346,439      $363,085
                                                          ========      ========

<PAGE>
Quarterly  interest  payments for the FRNs  commenced on February 15, 1996,  and
semiannual  interest payments for Series A Notes and Series B Bonds commenced on
May 15,  1996.  The Company  held $6.3  million and $8.4  million of the FRNs at
December 31, 2000 and 1999, 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

On April 8, 1998, the Company  converted the construction  project financing for
its Malitbog geothermal power project to term loans. OPIC is providing term loan
financing  of $46.8  million  that was fixed as of June 15,  1998 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
(9.005% at December 31, 2000). The loans have scheduled  repayments through June
2005.

On May 5, 1998, the Company converted the construction project financing for its
Upper Mahiao geothermal power project to term loans.  Export-Import  Bank of the
United States  ("Ex-Im Bank") is providing term loan financing 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  (9.7488% at December  31,  2000).  The loans have
scheduled repayments through June 2006.

On June 18, 1998, the Company  converted the construction  project financing for
its Mahanagdong  geothermal power project to term loans. Ex-Im Bank is providing
term  loan  financing  of  $154.6  million  at a fixed  rate of  6.92%.  OPIC is
providing  term loan  financing of $34.3  million that was fixed as of September
30,  1998 at an  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):
<TABLE>
<CAPTION>
                                                                                                                   MEHC
                                                                                                              (Predecessor)
Series                                         Issue Date            Due Date       Interest Rate     2000         1999
------                                         ----------            --------       -------------     ----         ----
<S>                                        <C>                          <C>            <C>          <C>          <C>
Series A-1 Senior Secured Bonds            September 10, 1999           2019           8.64%        $93,515      $93,515
Series A-2 Senior Secured Bonds            December 15, 1999            2019           8.79%         31,309       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            -
</TABLE>

CE Gas Loan

CE Gas, a wholly owned subsidiary of the Company, had borrowed $73.2 million and
$113.3 million on a (pound) 70 million  revolving  facility at December 31, 2000
and 1999, respectively, to fund the purchases of UK gas assets in the North Sea.
The amount  carries a variable  interest  rate based on LIBOR (6.67% at December
31, 2000). The revolving facility had utilized (pound) 49 million and (pound) 70
million at December 31, 2000 and 1999, respectively.

<PAGE>
Annual Repayments of Subsidiary and Project Debt

The annual repayments of the subsidiary and project debt for the years beginning
January 1, 2001 and thereafter are as follows (in thousands):

<TABLE>
<CAPTION>
                MidAmerican                     MidAmerican                      HomeServices
                 Funding,      MidAmerican        Energy          MidAmerican    Senior Notes
                LLC Senior       Energy          Pollution        Energy and         and             Salton
                 Notes and      Mortgage          Control           Capital       Revolving           Sea        Northern
                   Bonds          Bonds            Bonds             Notes           Debt            Bonds       Eurobonds
                ----------     -----------      -----------      -----------     -----------       ---------     ---------
<S>              <C>           <C>             <C>                 <C>            <C>             <C>            <C>
2001             $200,000      $      -        $   1,440           $123,333       $    742        $    632       $      -
2002                    -             -            1,440            185,574         10,718           2,108              -
2003                    -       100,000            5,320                  -            532           1,405              -
2004                    -        55,630                -                  -          5,094           1,757              -
2005                    -        90,500                -                  -          5,025           1,757        149,865
Thereafter        502,287        94,440          150,425            160,000         25,496         132,869        149,715
                 --------      --------         --------           --------       --------        --------       --------
                 $702,287      $340,570         $158,625           $468,907       $ 47,607        $140,528       $299,580
                 ========      ========         ========           ========       ========        ========       ========

                CE Electric
                 Funding                                            Cordova
                   Senior                                           Funding
                 Notes and     Casecnan        Philippine            Senior
                 Sterling      Notes and         Term               Secured         CE
                   Bonds         Bonds           Loans               Bonds        Gas Loan         TOTAL
                 --------      --------         --------           --------       -------         --------
2001             $      -      $ 26,301         $ 79,406           $      -       $  7,124        $438,978
2002                    -        32,213           68,259              1,238         19,902         321,452
2003                    -        41,468           72,148              9,000         19,116         248,989
2004              124,503        49,360           67,148              8,100         15,949         327,541
2005                    -        54,753           63,034              7,875         11,071         383,880
Thereafter        529,247       142,344           42,630            198,787              -       2,128,240
                ---------      --------         --------           --------       --------      ----------
                 $653,750      $346,439         $392,625           $225,000       $ 73,162      $3,849,080
                 ========      ========         ========           ========       ========      ==========

</TABLE>
9.   Income Taxes

Provision  for (benefit  from) income taxes was  comprised of the  following (in
thousands):
<TABLE>
<CAPTION>
                                                                                       MEHC (Predecessor)
                                                                 -------------------------------------------------------
                                              March 14, 2000     January 1, 2000          Year Ended       Year Ended
                                                 through             through             December 31,      December 31,
                                          December 31, 2000       March 13, 2000            1999              1998
                                          -----------------       --------------         -----------       ------------
<S>                                            <C>                   <C>                 <C>                <C>
Current:
    State.....................                 $10,527               $(1,886)            $  7,337           $ 5,677
    Federal...................                  17,387                 9,147              128,839            33,160
    Foreign...................                  40,823                16,012               13,889            20,096
                                               -------               -------             --------           -------
                                                68,737                23,273              150,065            58,933
                                               -------               -------             --------           -------
Deferred:
    State.....................                  (1,933)                  834                1,791               161
    Federal...................                 (32,469)                1,854              (75,510)           14,973
    Foreign...................                  18,942                 5,047               17,129            19,198
                                               -------               -------             --------           -------
                                               (15,460)                7,735              (56,590)           34,332
                                               -------               -------             --------           -------
    Total.....................                 $53,277               $31,008             $ 93,475           $93,265
                                               =======               =======             ========          ========

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

                                                                                                         MEHC (Predecessor)

                                              March 14, 2000        January 1, 2000       Year Ended        Year Ended
                                                 through               through            December 31,      December 31,
                                             December 31, 2000      March 13, 2000           1999              1998
                                             -----------------      --------------        -----------       -----------

Federal statutory rate...................        35.00%                35.00%               35.00%            35.00%
Percentage depletion in excess of
   cost depletion........................            -                     -                 (.38)            (3.52)
Investment and energy tax credits........        (2.26)                 (.66)               (1.78)             (.93)
State taxes, net of federal tax effect...         2.55                  (.75)                1.66              1.71
Goodwill amortization....................        12.13                  5.87                 5.46              2.51
Dividends on preferred
    securities of subsidiary trusts*.....       (11.11)                (2.80)               (3.75)            (4.63)
Tax effect of foreign income.............        (5.83)                (5.02)                 .36              1.86
Non-recurring items on Indonesia ........            -                     -               (10.99)                -
Dividends received deduction.............        (6.77)                (1.04)               (3.74)                -
Other items, net.........................          .59                  3.41                 4.34              2.28
                                                 -----                 -----                -----             -----
Effective tax rate.......................        24.30%                34.01%               26.18%            34.28%
                                                 =====                 =====                =====             =====
</TABLE>
*  Dividends  on  preferred  securities  of  subsidiary  trusts are  included in
minority interest.

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

                                                              MEHC (Predecessor)
                                                        2000             1999
                                                     ----------       ----------
Property, plant and equipment.....................    $866,678        $ 983,038
Income taxes recoverable through future rates.....     186,427          187,379
Demand side management............................       4,391           14,805
Reacquired debt...................................      10,256           12,476
                                                     ---------        ---------
                                                     1,067,752        1,197,698

Nuclear reserve and decommissioning................    (20,690)         (20,280)
Deferred income....................................     (8,883)         (19,502)
Deferred contract costs............................    (51,703)        (215,388)
Accruals not currently deductible for tax purposes.    (36,255)         (32,211)
Other..............................................     (5,193)          (7,449)
                                                     ---------        ---------
                                                      (122,724)        (294,830)
                                                     ---------        ---------
Net deferred income taxes..........................  $ 945,028        $ 902,868
                                                     =========        =========

<PAGE>
10.  Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary
     Trusts

The Company has organized  special purpose Delaware  business trusts ("Trust I",
"Trust II" and "Trust  III" or  collectively,  the  "Trusts")  pursuant to their
respective  amended  and  restated  declarations  of trusts  (collectively,  the
"Declarations").  On April 12, 1996,  February 26, 1997 and August 12, 1997, the
Company, through these Trusts, issued  Company-obligated  mandatorily redeemable
convertible  preferred  securities  (collectively,  the "Trust  Securities")  as
follows (in thousands):
                                                                      Conversion
           Issuer                Issue Date        Rate      Amount      Rate
----------------------------  -----------------    ----     --------  ----------
CalEnergy Capital Trust I     April 12, 1996       6.25%    $103,930    1.6728
CalEnergy Capital Trust II    February 26, 1997    6.25%    $180,000    1.1655
CalEnergy Capital Trust III   August 12, 1997      6.50%    $270,000    1.047

On March 14, 2000, the Company,  through  CalEnergy  Capital Trust 1, issued 11%
Company-obligated  manditorily  redeemable preferred securities of approximately
$454.8 million to Berkshire Hathaway.

On May 18, 1999,  CalEnergy  Capital  Trust I effected the  conversion of $103.9
million of the convertible  preferred  securities into approximately 3.5 million
shares of common stock of the Company.  The Securities  were converted at a rate
equivalent to a conversion price of $29.89 per share of Company common stock.

Throughout  2000,  CalEnergy  Capital  Trust II redeemed  approximately  477,000
shares of preferred  securities  at an  aggregate  cost of  approximately  $19.5
million.

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  $156.1 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 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.

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.

<PAGE>
The Debentures  may be redeemed by  MidAmerican  Energy on or after December 18,
2001,  or at an earlier  time if there is more than an  insubstantial  risk that
interest paid on the  Debentures  will not be deductible  for federal income tax
purposes.  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
such  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.

12. Preferred Stock

The  Company  distributed  a dividend  of one  preferred  share  purchase  right
("right")  for each  outstanding  share of  common  stock.  The  rights  are not
exercisable  until ten days after a person or group acquires or has the right to
acquire,  beneficial  ownership of 20% or more of the Company's  common stock or
announces a tender or  exchange  offer for 30% or more of the  Company's  common
stock.  Each right entitles the holder to purchase one  one-hundredth of a share
of Series A junior  preferred  stock for $52.  The rights may be redeemed by the
Board of Directors up to ten days after an event  triggering the distribution of
certificates for the rights. The rights are automatically attached to, and trade
with, each share of common stock.

In 1999, the Board of Directors renewed the Company's  shareholder  rights plan.
The  expiration  date of the rights plan was extended to September 14, 2009. The
amended  plan  reflects  prevailing  shareholder  rights plan  terms.  The share
ownership  level which  triggers  the exercise of the rights and the flip-in and
flip-over  features of the rights plan has been  reduced to 15% and the exercise
price of the rights has been increased to $140 per right. The Teton  Transaction
was  approved by the Board of  Directors  and did not trigger the  dividend of a
preferred share purchase right.

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 options are fully vested and 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  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.

<PAGE>
The methods and assumptions used to estimate fair value are as follows:

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.

<TABLE>
<CAPTION>
                                                                                                    MEHC (Predecessor)
                                                                               2000                       1999
                                                                       -----------------------   -----------------------
                                                                                     Estimated                 Estimated
                                                                       Principal       Fair       Principal       Fair
                                                                        Amount         Value       Amount        Value
                                                                       ---------    ----------   ---------     ---------
                                                                                         (in thousands)
<S>                                                                   <C>           <C>          <C>          <C>
9.5% Senior Notes                                                     $       32    $       34   $       32   $       34
7.63% Senior Notes                                                       350,000       360,115      350,000      346,220
Limited Recourse Senior Secured Notes                                          -             -        4,225        4,449
$1.4 Billion Senior Notes                                              1,400,000     1,447,581    1,400,000    1,396,360
$100 Million Senior Notes                                                101,888       102,020      102,061       97,920
Revolving Credit Facilities                                               85,000        85,000            -            -
MidAmerican Funding, LLC Senior Notes and Bonds                          702,287       657,300      702,089      638,101
MidAmerican Energy Mortgage Bonds                                        340,570       345,692      450,570      445,502
MidAmerican Energy Pollution Control Bonds                               158,625       158,914      159,129      159,868
MidAmerican Energy Notes                                                 422,240       420,496      260,240      247,084
MidAmerican Energy Commercial Paper                                       81,600        81,600      204,000      204,000
MidAmerican Capital Notes                                                 46,667        46,464       70,098       71,526
HomeServices Senior Notes and Revolving Debt                              47,607        44,094       48,817       44,862
Salton Sea Bonds                                                         140,528       116,947      140,528      128,815
Northern Eurobonds                                                       299,580       357,456      324,850      379,987
CE Electric UK Funding Company Senior Notes
    and Sterling Bonds                                                   653,750       694,031      670,327      671,779
Casecnan Notes and Bonds                                                 346,439       319,056      363,085      353,789
Northern Short Term Treasury Loan                                         83,166        83,166      175,523      175,523
Cordova Funding Senior Secured Bonds                                     225,000       224,018      124,824      120,399
CE Gas Loan                                                               73,162        73,162      113,267      113,267
Company-obligated preferred securities of subsidiary trusts              880,840       769,605      450,000      353,925
Subsidiary-obligated preferred securities of subsidiary trusts           100,000        98,752      101,598       87,240
Preferred Securities of Subsidiaries                                     145,686       131,255      146,606      135,216


</TABLE>
<PAGE>
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):
<TABLE>
<CAPTION>
                                                                                            2000
                                                                ---------------------------------------------------------
                                                                 Amortized      Unrealized        Unrealized       Fair
                                                                    Cost           Gains            Losses         Value
                                                                ------------    -----------      -----------     --------
        <S>                                                       <C>             <C>               <C>           <C>
        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...........................        25,449             48           (1,025)        24,472
             Cash equivalents...............................        11,150              -                -         11,150
                                                                  --------       --------         --------       --------
                                                                  $174,150       $ 36,392         $ (8,315)      $202,227
                                                                  ========       ========         ========       ========

                                                                                     MEHC (Predecessor)
                                                                                            1999
                                                                ----------------------------------------------------------
                                                                 Amortized      Unrealized       Unrealized         Fair
                                                                    Cost           Gains           Losses           Value
                                                                -------------   -----------      -----------      --------
         Available-for-sale:
             Equity securities..............................      $122,327       $ 37,941         $(13,530)      $146,738
             Municipal bonds................................        30,913            868             (355)        31,426
             U. S. Government securities....................        14,159             78             (123)        14,114
             Corporate securities...........................        26,935              5           (1,511)        25,429
             Cash equivalents...............................         8,591              -                -          8,591
                                                                  --------       --------         --------       --------
                                                                  $202,925       $ 38,892         $(15,519)      $226,298
                                                                  ========       ========         ========       ========
</TABLE>

15.   Accounting for Derivatives

MidAmerican Energy

MidAmerican Energy uses gas futures contracts  and swap  contracts to reduce the
volatility in the price of natural gas purchased to meet the needs of its  regu-
lated customers,  to hedge the  impact of changing prices on margins earned from
nonregulated  as sales and to take trading  positions at levels permitted by its
risk  management  policy.  Investments  in natural gas futures  contracts, which
total  $4.8  million and  $0.6 million as of December 31, 2000 and 1999, respec-
tively, are included in receivables on the  consolidated  balance sheets.  Gains
and losses  on gas futures  contracts  that  qualify  for hedge  accounting  are
deferred and reflected as  adjustments  to the carrying value of the hedged item
or included in other assets on the  consolidated balance sheets until the under-
lying  physical  transaction is recorded  if the instrument is used  to hedge an
anticipated future transaction. The net gain or loss on gas futures contracts is
included in the  determination  of income in the  same period as the expense for
the physical  delivery of the  natural gas.  Realized  gains  and  losses on gas
futures  contracts  and the net amounts  exchanged or accrued  under the natural
gas swap contracts are included in cost of  sales.  Deferred  net gains/(losses)
related to  MidAmerican  Energy's  gas futures  contracts  are $7.6  million an
$(0.4) million as of December 31, 2000 and 1999, respectively.

MidAmerican Energy uses natural gas derivative  instruments for trading purposes
under  strict  value  at risk  guidelines  outlined  by  senior  management.  In
accordance  with the FASB's  Emerging Issues Task Force Abstract No. 98-10 (EITF
98-10),  derivative  instruments  held for trading purposes are recorded at fair
value and any  unrealized  gains or losses are reported in earnings.  EITF 98-10
has not had a material effect on the Company's  financial  position,  results of
operations or cash flows.

<PAGE>
MidAmerican  Energy also uses electric  forward  contracts to hedge  anticipated
future sales of  electricity.  Realized  gains or losses on electric  derivative
products are included in cost of sales on the consolidated statements of income.
Unrecognized  net losses related to MidAmerican  Energy's  electric  derivatives
total $4.7 million and zero as of December 31, 2000 and 1999, respectively.

MidAmerican Energy  periodically  evaluates the effectiveness of its natural gas
and electricity hedging programs. If a high degree of correlation between prices
for the  hedging  instruments  and  prices  for  the  physical  delivery  is not
achieved,  the  contracts are recorded at fair value and the gains or losses are
included in the determination of income. MidAmerican Energy also uses derivative
instruments for trading  purposes.  The following  derivative  instruments  were
outstanding at December 31:

<TABLE>
<CAPTION>
                                                                       2000                              1999
                                                             --------------------------       ----------------------------
                                                                            Weighted                           Weighted
                                                                            Average                            Average
                                              Unit of         Notional       Market            Notional         Market
                                              Measure          Volume    Value Per Unit         Volume      Value Per Unit
                                              -------         --------   --------------        --------     --------------
<S>                                            <C>          <C>            <C>                <C>              <C>
Hedging Instruments:
    Natural Gas Futures - Long............     MMBtu         1,630,000     $   9.46            2,700,000       $   2.34
    Natural Gas Futures - (Short) ........     MMBtu          (170,000)    $  (9.78)          (3,250,000)      $  (2.34)
    Natural Gas Swaps.....................     MMBtu        24,106,980     $   0.33           85,520,442       $  (0.02)
    Natural Gas Options - Long ...........     MMBtu         1,790,280     $   0.53                    -            -
    Electric Forwards - (Short) ..........     MWh            (139,200)     $(33.99)                   -            -
Trading instruments:
    Natural Gas Futures - NYMEX(Short)....     MMBtu           (20,000)     $(15.92)                   -            -
    Natural Gas Swaps.....................     MMBtu           (10,000)     $(26.14)                   -            -
</TABLE>

Northern

Northern  utilizes  contracts for differences  ("CFDs"),  as part of the overall
risk management  strategy of its electricity  supply  business,  to mitigate its
exposure  to  volatility  in the  price of  electricity  purchased  through  the
electricity pool (the "Pool").

The portfolio of CFDs held for risk management  purposes is established to match
the notional quantity of the expected or committed transaction volumes that will
be subject to commodity  price risk over the same time period.  The portfolio is
therefore  managed to complement the expected  electricity  purchase transaction
portfolio,  thereby reducing electricity price change risk to within  acceptable
limits.

As a  consequence,  the value of the portfolio of CFDs,  which are held for risk
management  purposes,  is directly  linked to the  hypothetical  changes in Pool
price,  such  that an  adverse  movement  in Pool  price  would be  offset  by a
compensating impact on the contract. For the specified volumes,  therefore,  the
impact of pool risk is constrained at a pre-determined level, assuming:

(iii)    The CFD is not closed in advance of its agreed term.
(iv)     The  level of purchase  occurs as expected, matching volumes covered by
         the CFD.

Therefore,  disclosure  in  respect  to CFDs  relies on the  assumption that the
contracts exist in parallel to underlying actual  electricity purchases.  In the
absence of such purses the contract  would  generate a loss or gain dependent on
the pool prices prevailing over the periods covered by the contract terms. As of
December 31, 2000, the national amount of executed CFDs was approximately $590.4
million, representing approximately 18% of the expected or committed transaction
volumes  through  December 31,  2004.  The fair value of these  contracts  was a
liability of  approximately  $30.5 million  discounted at 15%, based upon quoted
market prices at December 31, 2000. A hypothetical decrease of 10% in the market
price of  electricity  from the December 31, 2000 levels would further  decrease
the fair value of these contracts by approximately  $49.5 million.  However,  as
stated  above,  the  value of the  portfolio  of CFDs,  which  are held for risk
management  purposes,  is  directly  liked to the  hypothetical  changes in Pool
price,  such that a  movement  in Pool price  would be offset by a  compensating
impact on the contract.

<PAGE>

The following  derivative  instruments at Northern were  outstanding at December
31:
<TABLE>
<CAPTION>
                                                                                  2000                           1999
                                                              -------------------------------  ---------------------------
                                                                                 Weighted                        Weighted
                                                                                 Average                          Average
                                                 Unit of        Notional          Market         Notional          Market
                                                 Measure         Volume       Value Per Unit      Volume      Value Per Unit
                                                 -------         ------       --------------      ------      --------------
<S>                                               <C>          <C>               <C>            <C>               <C>
Hedging Instruments:
  Net Contracts for Differences - Long            MWh          17,080,000        $28.96         14,981,000        $36.49

</TABLE>

16.  Securitization of Accounts Receivable

In  December  1998,  Northern  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 allows Northern 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, Northern
received $161 million in cash associated with the agreement.  As of December 31,
2000, approximately $37 million was accounted for as a loan.

In 1997 MidAmerican Energy entered into a revolving agreement,  which expires in
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, 2000, the revolving cash balance was $70
million,  and the  amount  outstanding  under the  subordinated  note was $114.9
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, 2000, $185.8 million of accounts receivable,  net of reserves,  was
sold under the agreement.

17. Regulatory Matters

Northern

Northern  is  subject  to  price  cap  regulation  and  the  Office  of Gas  and
Electricity Markets ("Ofgem") enforces the price control formulas for the supply
and distribution businesses.

The current  distribution  price control  period  expires on March 31, 2002. The
current  formula  requires  that  regulated  distribution  income  per  unit  is
increased or decreased each year by RPI-Xd where RPI reflects the average of the
twelve months' inflation rates recorded for the previous July to December period
and Xd is 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.

Northern's  current  supply  price  control  applies  only to domestic  and some
smaller non-domestic customers in the North East of England and is due to expire
on March 31,  2002.  The  current  formula  took  effect on April 1, 2000.  This
control relates to domestic  customers only and led to a further price reduction
for those customers of 10.8% beginning on April 1, 2000.

<PAGE>
MidAmerican Energy

Under a 1997 pricing plan settlement  agreement resulting from an Iowa Utilities
Board rate proceeding,  electric prices for MidAmerican Energy's Iowa industrial
and  commercial  customers  were reduced  through a retail access pilot project,
negotiated  individual electric contracts and a tariffed rate reduction for some
non-contract commercial customers.

The negotiated electric contracts have differing terms and conditions as well as
prices. The vast majority of the contracts expire during the period 2003 through
2005,  although some large  customers have contracts  extending to 2008. Some of
the  contracts  have  price  renegotiation  and  early  termination   provisions
exercisable  by either  party.  Prices are set as fixed  prices;  however,  many
contracts allow for potential price  adjustments  with respect to  environmental
costs,  government imposed public purpose programs,  tax changes, and transition
costs. While the contract prices are fixed (except for the potential  adjustment
elements),  the costs MidAmerican  Energy incurs to fulfill these contracts will
vary. On an aggregate basis the annual revenues under contract are approximately
$180 million.

Under the 1997 pricing plan settlement agreement, if MidAmerican Energy's annual
Iowa electric  jurisdictional return on common equity exceeds 12%, then earnings
above the 12% level will be shared  equally  between  customers and  MidAmerican
Energy. If the return exceeds 14%, then two-thirds of MidAmerican Energy's share
of those earnings above the 14% level will be used for  accelerated  recovery of
certain  regulatory  assets.  During 2000,  MidAmerican  Energy  credited  $14.8
million to its Iowa non-contract customers related to the return calculation for
1999,  which was approved by the Iowa  Utilities  Board,  subject to  additional
refund. In 2000,  MidAmerican  Energy accrued $21.6 million for customer credits
relating to 2000  operations.  This Iowa electric  retail  revenue  sharing plan
remained in effect through the year 2000.  The rates  established by the pricing
plan  settlement  agreement  will  remain in  effect  until  either  the plan is
renegotiated  or a change  in  rates is  approved  by the Iowa  Utilities  Board
pursuant to a rate proceeding.

The pricing plan  settlement  agreement also precluded  MidAmerican  Energy from
filing for increased rates prior to January 1, 2001 unless the return fell below
9%. Other parties  signing the agreement were prohibited form filing for reduced
rates prior to 2001 unless the return,  after  reflecting  credits to customers,
exceeded  14%.  The  agreement  also  eliminated   MidAmerican  Energy's  energy
adjustment clause,  and, as a result, the cost of fuel is not directly passed on
to customers.

On March 14, 2001, the Office of the Consumer Advocate of the Iowa Department of
Justice filed a petition  with the Iowa  Utilities  Board to reduce  MidAmerican
Energy's Iowa retail electric rates by approximately $77 million annually.  This
filing will be contested  by  MidAmerican  Energy and,  under Iowa law, the Iowa
Utilities Board must rule on the petition within ten months from March 14, 2001.
Iowa provides that the rates collected after the filing the petition are subject
to refund  with  interest  if they  exceed  rates  finally  approved by the Iowa
Utilities Board.

Under an Illinois restructuring law enacted in 1997, a similar sharing mechanism
is in place for MidAmerican  Energy's Illinois electric  operations.  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 2000  through  2004.  The  two-year  average  above  which
sharing  must occur for 2000 was 12.83%.  Using the same 30-year  Treasury  Bond
average, the computed level or return would be 14.33% for 2001 through 2004. The
law allows  MidAmerican  Energy to mitigate  the  sharing of earnings  above the
threshold  return on common equity  through  accelerated  recovery of regulatory
assets.

<PAGE>
18. Pension Commitments

United Kingdom Operations

Northern  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.

The actuarial  computation for December 31, 2000, 1999 and 1998 assumed interest
rates of 6.0%, 6.0% and 5.5% respectively,  an expected return on plan assets of
6.5%, 6.5% and 6.0%,  respectively,  and annual compensation  increases of 3.0%,
3.0% and 3.5%,  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. Northern's funding policy for the plan is to
contribute  annually at a rate that is intended to remain a level  percentage of
compensation for the covered employees.

The following  table details the funded status and the amount  recognized in the
consolidated balance sheets for Northern's plan as of December 31, 2000 and 1999
(in thousands):

                                                              MEHC (Predecessor)

                                                      2000               1999
                                                  -----------         ----------

Change in benefit obligation:
Benefit obligation at beginning of year........   $  940,600         $  926,000
Service cost...................................        8,660             10,200
Interest cost..................................       50,765             48,500
Participant contributions......................        4,927              5,700
Benefits paid..................................      (49,272)           (53,700)
FAS 88 curtailment.............................        6,570             38,300
Experience gain and change of assumptions......      (10,697)           (34,400)
                                                   ---------          ---------
Benefit obligation at end of the year..........      951,553            940,600
                                                   ---------          ---------

Change in plan assets:
Fair value of plan assets at beginning of the
  year.........................................    1,283,600          1,143,100
Actual return on plan assets...................      (73,741)           181,600
Employer contributions.........................          597              6,946
Participant contributions......................        4,927              5,654
Benefits paid..................................      (49,272)           (53,700)
                                                  ----------         ----------
Fair value of plan assets at end of the year...    1,166,111          1,283,600
                                                  ----------         ----------

Funded status..................................      214,558            343,000
Unrecognized net (loss) gain...................      (77,193)           300,100
                                                  ----------         ----------
Prepaid benefit cost...........................   $  291,751         $   42,900
                                                  ==========         ==========

As a result of the distribution  price reviews in 1999,  Northern  implemented a
review  of  staffing  requirements   primarily  in  its  distribution  business.
Following  discussions with the trade unions,  Northern 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.

<PAGE>
Net periodic  pension cost (benefit) for Northern's plan for 2000, 1999 and 1998
included the following components (in thousands):

                                                         MEHC (Predecessor)
                                                 ------------------------------
                                March 14, 2000   January 1, 2000
                                    through         through
                               December 31, 2000  March 13, 2000  1999     1998
                               -----------------  --------------  ----     ----
Service cost - benefits
  earned during the period.......   $  6,933       $  1,727   $ 10,200 $ 12,600
Interest cost on projected
  benefit obligation.............     40,640         10,125     48,500   58,800
Expected return on plan assets...    (50,800)       (12,657)   (59,500) (68,000)
                                    --------      --------   --------  --------
Net periodic pension cost
  (benefit)......................   $ (3,227)      $  (805)   $  (800) $  3,400
                                    ========       =======    =======  ========

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 health care and life insurance
(postretirement) 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:

                                                         MEHC (Predecessor)
                                                 -------------------------------
                                March 14, 2000   January 1, 2000    Year
                                   through           through        Ended
                              December 31, 2000 March 13, 2000 December 31, 1999
                              ----------------- -------------- -----------------
Pension Cost

Service cost..............      $  13,014       $   3,242         $   9,854
Interest cost.............         28,329           7,058            25,505
Expected return on
  plan assets.............        (38,532)         (9,600)          (37,392)
Amortization of net
  transition obligation...         (2,074)           (517)                -
Amortization of prior
  service cost............          2,310             575                 -
Amortization of prior
  year gain...............         (3,297)           (822)                -
Curtailment loss..........              -               -             4,270
                                 --------        --------          --------
  Net periodic pension
    cost (benefit)........       $   (250)       $    (64)         $  2,237
                                 ========        ========          ========

<PAGE>
                                                        MEHC (Predecessor)
                                               ---------------------------------
                             March 14, 2000    January 1, 2000       Year
                                through            through           Ended
Postretirement Cost         December 31, 2000  March 13, 2000  December 31, 1999
                            -----------------  --------------  -----------------
Service cost..............       $  2,089         $    520         $  2,478
Interest cost.............          6,688            1,666            6,423
Expected return on
  plan assets.............         (3,947)            (984)          (3,540)
Amortization of net
  transition obligation...          3,290              820                -
Amortization of prior
  service cost............            340               85                -
Amortization of prior
  year gain...............           (699)            (174)               -
                                  -------          -------          -------
  Net periodic pension
    cost .................        $ 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,   2000,   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 $44.7 million and $37.9 million at December 31, 2000
and 1999, 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 $4.3 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 $82.7 million and $77.5 million,
respectively,  as of  December  31, 2000 and $68.8  million  and $65.5  million,
respectively, as of December 31, 1999.

<PAGE>

The  following  table  presents a  reconciliation  of the  beginning  and ending
balances  of the  benefit  obligation,  fair value of plan assets and the funded
status of the Company plans to the net amounts  recognized  in the  consolidated
balance sheet as of December 31 (dollars in thousands):
<TABLE>
<CAPTION>
                                                                                                        MEHC (Predecessor)
                                                                                                 -------------------------------
                                                                   2000             2000             1999            1999
                                                                 Pension        Postretirement     Pension       Postretirement
                                                                 Benefits          Benefits        Benefits         Benefits
                                                                 --------          --------        --------         --------
<S>                                                             <C>               <C>              <C>             <C>
Reconciliation of benefit obligation:
Benefit obligation at beginning of year....................     $447,170          $107,744         $456,475        $120,188
Service cost...............................................       16,256             2,609           12,192           3,066
Interest cost..............................................       35,387             8,354           31,556           7,947
Participant contributions..................................           74             2,395              107           1,838
Plan amendments............................................         (132)                -           14,823           2,775
Actuarial (gain) loss......................................        6,007            20,589          (41,567)        (18,248)
Curtailment................................................            -                 -             (705)              -
Termination benefits.......................................            -                 -            3,471               -
Benefits paid..............................................      (32,413)           (9,869)         (29,182)         (9,822)
                                                                 -------           -------          -------         -------
    Benefit obligation at end of year......................      472,349           131,822          447,170         107,744
                                                                 -------           -------          -------         -------

Reconciliation of the fair value of plan assets:

Fair value of plan assets at beginning of year.............      605,059            72,622          524,508          63,093
Employer contributions.....................................        4,355            10,543            4,201          12,405
Participant contributions..................................           74             2,395              107           1,838
Actual return on plan assets...............................      (21,867)             (601)         105,425           5,108
Benefits paid..............................................      (32,413)           (9,869)         (29,182)         (9,822)
                                                                 -------           -------          -------         -------
    Fair value of plan assets at end of year...............      555,208            75,090          605,059          72,622
                                                                 -------           -------          -------         -------

Funded status..............................................       82,859           (56,732)         157,889         (35,122)
Unrecognized net (gain) loss...............................     (130,423)            1,326         (101,434)        (18,943)
Unrecognized prior service cost............................       24,962             4,689            9,540           2,776
Unrecognized net transition obligation (asset).............       (8,566)           49,322                -               -
                                                                --------           -------          -------         -------
    Net amount recognized in the consolidated balance.

    sheet..................................................     $(31,168)         $ (1,395)        $ 65,995        $(51,289)
                                                                ========          ========         ========        ========

                                                                                                        MEHC (Predecessor)
                                                                                                -------------------------------
                                                                   2000             2000             1999            1999
                                                                 Pension        Postretirement     Pension       Postretirement
                                                                 Benefits          Benefits        Benefits          Benefits
                                                                 --------          --------        --------          --------
Amounts recognized in the consolidated balance sheet consist of:

Prepaid benefit cost.......................................     $ 16,773          $  1,493         $108,907        $  1,042
Accrued benefit liability..................................      (77,538)           (2,888)         (65,533)        (52,331)
Intangible asset...........................................       25,510                 -           22,621               -
Accumulated other comprehensive income.....................        4,087                 -                -               -
                                                                --------          ---------        --------        --------
    Net amount recognized..................................     $(31,168)         $ (1,395)        $ 65,995        $(51,289)
                                                                ========          ========         ========        ========
</TABLE>
<PAGE>
                                                      Pension and Postretirement

                                                              Assumptions
                                                              -----------
                                                              MEHC (Predecessor)

                                                       2000              1999
                                                       ----              ----
Assumptions used were:
Discount rate......................................    7.00%             7.75%
Rate of increase in compensation levels............    5.00%             5.00%
Weighted average expected long-term
    rate of return on assets.......................    9.00%             9.00%

For purposes of calculating the postretirement benefit obligation, it is assumed
health care costs for covered  individuals prior to age 65 will increase by 6.5%
in 2001 and that the rate of increase  thereafter  will  decrease to an ultimate
rate of 5.5% by the year 2004. For covered  individuals  age 65 and older, it is
assumed health care costs will increase by 5.5% annually.

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 2000 would  increase by $1.6 million,  and the  postretirement
benefit obligation at December 31, 2000, would increase by $16.5 million. If the
assumed  health care trend rates were to decrease by 1.0%, the total service and
interest  cost for 2000 would  decrease by $1.4  million and the  postretirement
benefit obligation at December 31, 2000, would decrease by $15.1 million.

19.  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.  Based  on  public  announcements,  the  Company
understands  that Edison has not made  payments to other  qualifying  facilities
("QFs") from which Edison purchases power and has not made scheduled payments of
debt service.  Edison's  senior  unsecured debt  obligations are currently rated
Caa2 (on watch for possible downgrade) by Moody's and D by S&P.

The  Company is aware that there have been  public  announcements  that  Edison,
other  industry  participants  and  governmental  entities have taken actions in
response to Edison's financial condition. These actions include the following:

o        The Federal Energy Regulatory  Commission  ("FERC") has issued an order
         eliminating  requirements  that Edison and other  California  utilities
         purchase power from the structured  power market in California in order
         to provide them with an  opportunity  to obtain power from  alternative
         sources at a lower cost.

o        The State of  California  has  enacted  legislation  to provide for the
         California  Department of Water  Resources to purchase  wholesale power
         and sell it to retain customers, which will be funded by a surcharge on
         retail rates.  The  California  legislature is also  considering  other
         legislation  to  improve  the  financial  condition  of the  California
         electric utilities.

o        The California Public Utilities Commission ("CPUC") approved a decision
         on March 27, 2001 to increase retail electricity rates by approximately
         40%. In another  decision that day, the CPUC ordered  Edison to pay QFs
         on a go forward  basis  within 15 days of the invoice  and  purportedly
         modified the calculation of Short Run Avoided Cost.

o        The  State of  California  and  Edison  have  announced  a  preliminary
         agreement for the State to purchase  Edison's  transmission  assets for
         $2.7  billion  and to allow  Edison to issue  bonds  for a  substantial
         portion of its under collection or revenues.

<PAGE>
The Company can give no assurance as to the likely  result of any of the actions
described above or as to whether such actions will have a positive effect on the
financial  condition of Edison or its  willingness  to make  payments  under the
Power Purchase Agreements.

Edison  has  failed  to pay  approximately  $76  million  due  to CE  Generation
affiliates  under the Power Purchase  Agreements for power delivered in November
and  December  2000 and January  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 and March 2001. Edison has not notified
the Company as to when it can expect to receive these  payments.  This continued
non-payment  by Edison could result in an untenable  situation for the continued
operation of the Imperial Valley Projects unless  additional  funds are obtained
in the near future.

On February  21, 2001,  the Imperial  Valley  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 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'  Motion for Summary  Adjudication  and a Declaratory  Judgment
ordering  that:  1) under the Power  Purchase  Agreements,  the Imperial  Valley
Projects have the right to temporarily suspend deliveries of capacity and energy
to Edison, 2) the Imperial Valley 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.  The Imperial  Valley  Projects  intend to vigorously
pursue  its  other  remedies  in this  action  in light of  Edison's  continuing
non-payment.

The Company is hopeful that the current  Edison  situation is temporary  and the
proceedings in the legal,  regulatory,  financial and political arenas will lead
to the  improvement of Edison's  financial  condition in the near future and the
payment by Edison of amounts due under the Power Purchase  Agreements.  However,
no assurance can be given that this will be the case.

As a result  of  Edison's  failure  to make the  payments  due  under  the Power
Purchase  Agreements  and the recent  downgrades  of  Edison's  credit  ratings,
Moody's has  downgraded  the ratings  for the Salton Sea Funding  Corp.  project
related debt to Caa2  (negative  outlook) and S&P has downgraded the ratings for
the  project  related  debt to BBB- and has placed the project  related  debt on
"credit watch negative".  Accordingly,  the Funding Corporation does not believe
it is currently able to obtain funds in the banking or capital markets. However,
a  failure  by Edison  to make  these  payments  as well as  subsequent  monthly
payments,  for a  substantial  period of time after the payments are due, is not
expected to have a material adverse effect on the ability of the Company to make
payments on its debt obligations. However, there can be no assurance that such a
failure by Edison would not cause a material adverse effect.

B.  Decommissioning Costs

Based on  site-specific  decommissioning  studies that include  decontamination,
dismantling,  site restoration and dry fuel storage cost,  MidAmerican  Energy's
share of expected  decommissioning  costs for Cooper and Quad Cities Station, in
2000  dollars,  is $277  million and $266  million,  respectively.  In Illinois,
nuclear  decommissioning  costs are  included  in  customer  billings  through a
mechanism  that permits  annual  adjustments.  These costs are reflected in base
rates in Iowa tariffs.

For purposes of developing a decommissioning  funding plan for Cooper,  Nebraska
Public Power District ("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.

<PAGE>
As of  December  31,  2000,  MidAmerican  Energy's  share of funds  set aside in
internal  and external  accounts  for  decommissioning  was $128.6  million.  In
addition,  the funding plan also assumes  various  funds and reserves  currently
held to satisfy NPPD bond  resolution  requirements  will be available for plant
decommissioning costs which is to begin with a 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.
MidAmerican Energy's expense for Cooper decommissioning components was $11.5 and
$9.1 million, for the year ended December 31, 2000 and the period from March 12,
1999 through  December 31, 1999 and is included in operating  expense.  Earnings
from the internal  account and external trust fund, which are recognized by NPPD
as the owner of the plant,  are tax exempt  and serve to reduce  future  funding
requirements.

External  trusts  have  been   established  for  the  investment  of  funds  for
decommissioning  the Quad  Cities  Station.  The  total  accrued  balance  as of
December 31, 2000, was $153.1 million and is included in other long-term accrued
liabilities and a like amount is reflected in nuclear decommissioning trust fund
and other marketable securities and represents the fair value of the assets held
in the trusts.

MidAmerican  Energy's provision for depreciation  included costs for Quad Cities
Station nuclear decommissioning of $8.3 million for year ended December 31, 2000
and $8.2 million for the period from March 12, 1999  through  December 31, 1999.
The provision charged to 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%.  Earnings,  net of investment fees, on the assets
in the trust fund were $1.9  million  for the year ended  December  31, 2000 and
$1.6 million for the period from March 12, 1999 through December 31, 1999.

C.  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 the 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.

The 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  that  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.

<PAGE>
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, with coverage limits totaling $2.1 billion. For Cooper, MidAmerican
Energy and the 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 the 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 $8.5 million.

The master nuclear worker liability coverage, which is purchased by the 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 of
workers in nuclear-related industries.

20.  Segment Information:

The Company has identified five reportable  business segments  principally based
on    management    structure:    CalEnergy    Generation-Domestic,    CalEnergy
Generation-Foreign  (primarily the Philippines),  MidAmerican  (domestic utility
operations), Northern (foreign utility operations) and HomeServices (real estate
operations).  Information related to the Company's reportable operating segments
are shown below (in thousands).
<TABLE>
<CAPTION>
                                                                                      MEHC (Predecessor)
                                                                   -----------------------------------------------------
                                       March 14, 2000              January 1, 2000
                                          through                      through                Year Ended December 31,
                                                                                            ----------------------------
                                       December 31, 2000          March 13, 2000            1999                   1998
                                       -----------------          --------------            ----                   ----
<S>                                      <C>                      <C>                   <C>                  <C>
Revenue: (1)
CalEnergy Generation-Domestic........    $     40,031             $     4,520           $    105,869         $    583,311
CalEnergy Generation-Foreign.........         156,504                  42,726                210,571              223,650
MidAmerican..........................       1,930,122                 447,583              1,469,348                    -
Northern.............................       1,517,539                 499,017              2,098,976            1,842,930
HomeServices.........................         405,805                  66,880                357,728                    -
                                         ------------             -----------            -----------         ------------
Segment Revenue......................       4,050,001               1,060,726              4,242,492            2,649,891
Corporate............................          (9,403)                  1,830                 29,420               32,820
                                         ------------             -----------           ------------         ------------
                                         $  4,040,598             $ 1,062,556           $  4,271,912         $  2,682,711
                                         ============             ===========           ============         ============
Depreciation and Amortization

CalEnergy Generation-Domestic........    $      2,183             $       250           $     14,478         $    122,111
CalEnergy Generation-Foreign.........          52,685                  13,514                 66,063               65,729
MidAmerican..........................         184,955                  45,184                182,638                    -
Northern.............................         108,637                  31,964                137,963              130,404
HomeServices.com.....................           8,695                   2,891                  7,772                    -
                                         ------------             -----------           ------------         ------------
Segment Depreciation.................         357,155                  93,803                408,914              318,244
Corporate/other......................          26,196                   3,475                 18,776               15,178
                                         ------------             -----------           ------------         ------------
                                         $    383,351             $    97,278           $   427,690          $    333,422
                                         ============             ===========           ===========          ============

<PAGE>
                                                                                        MEHC (Predecessor)
                                                                   ------------------------------------------------------
                                       March 14, 2000              January 1, 2000
                                           through                     through                 Year Ended December 31,
                                                                                              -------------------------
                                     December 31, 2000              March 13, 2000            1999                 1998
                                     -----------------              --------------            ----                 ----
Interest Expense net

CalEnergy Generation-Domestic........    $      1,829             $       793           $     17,851          $    80,721
CalEnergy Generation-Foreign.........          34,458                   9,713                 58,322               71,270
MidAmerican..........................          94,425                  24,579                100,046                    -
Northern.............................          74,335                  21,189                 96,759               83,985
HomeServices.com.....................           2,328                     785                  3,228                    -
                                         ------------             -----------           ------------          -----------
Segment Interest Expense, net........         207,375                  57,059                276,206              235,976
Corporate/other......................         104,029                  28,755                149,967              111,316
                                         ------------             -----------           ------------          -----------
                                         $    311,404             $    85,814           $    426,173          $   347,292
                                         ============             ===========           ============          ===========

Income before provisions for income taxes: (1)
CalEnergy Generation-Domestic........    $     30,697             $     2,877           $     49,095           $  232,303
CalEnergy Generation-Foreign.........          49,787                  15,976                 68,105               72,693
MidAmerican..........................         181,797                  63,315                151,555                    -
Northern.............................          83,108                  58,673                152,126               88,787
HomeServices.........................          31,015                  (4,929)                16,613                    -
                                         ------------             -----------            -----------            ---------
Segment income.......................         376,404                 135,912                437,494              393,783
Corporate............................        (157,200)                (37,137)              (164,720)            (121,730)
                                         ------------             ------------           -----------            ----------
                                         $    219,204             $    98,775            $   272,774           $  272,053
                                         ============             ===========            ===========           ==========
Capital expenditures:

CalEnergy Generation-Domestic........    $    151,289             $    53,011            $   145,255          $   105,458
CalEnergy Generation-Foreign.........          87,781                  22,263                 95,552              204,301
MidAmerican..........................         194,045                  23,977                194,216                    -
Northern (2).........................         109,174                  15,701                202,073              184,631
HomeServices.........................           6,996                   2,052                  9,143                    -
                                         ------------             -----------            -----------          -----------
Segment capital expenditures.........         549,285                 117,004                646,239              494,390
Corporate............................           2,812                      28                    120                  537
                                         ------------             -----------            -----------          -----------
                                         $    552,097             $   117,032            $   646,359          $   494,927
                                         ============             ===========            ===========          ===========
</TABLE>
(1) Before non-recurring items.
(2) Capital  expenditures  at the foreign utility exclude the effect of exchange
rate changes.
<PAGE>
                                                                        MEHC
                                                                   (Predecessor)
                                                          As of December 31,
                                                          ------------------
                                                        2000            1999
                                                    -------------    -----------
Identifiable assets:

CalEnergy Generation-Domestic...........          $   968,444       $  858,812
CalEnergy Generation-Foreign............            1,188,445        1,270,516
MidAmerican.............................            5,392,273        5,072,788
Northern................................            2,929,665        2,972,705
HomeServices............................              163,101          162,714
                                                  -----------      -----------
Segment identifiable assets.............           10,641,928       10,337,535
Corporate...............................            1,038,723          428,817
                                                  -----------      -----------
                                                  $11,680,651      $10,766,352
                                                  ============     ===========

Long-lived assets:

CalEnergy Generation-Domestic...........          $  731,276       $   595,607
CalEnergy Generation-Foreign............             960,835           956,433
MidAmerican.............................           4,079,250         3,995,763
Northern................................           2,127,175         2,438,877
HomeServices............................             125,894           128,024
                                                  ----------        ----------
Segment long-lived assets...............           8,024,430         8,114,704
Corporate...............................             997,367            61,302
                                                  ----------        ----------
                                                  $9,021,797        $8,176,006
                                                  ==========        ==========

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 and related amortization.

<PAGE>

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, 2000 for the Company and as of December 31, 1999
for MEHC (Predecessor),  and the related consolidated  statements of operations,
stockholders' equity, and cash flows for the period January 1, 2000 to March 13,
2000 for MEHC  (Predecessor)  and for the period  March 14, 2000 to December 31,
2000 for the  Company,  and for the years ended  December  31, 1999 and 1998 for
MEHC  (Predecessor).  Our audits also included the financial  statement schedule
listed  in the  Index at Item  14.  These  financial  statements  and  financial
statement  schedule are the  responsibility  of the  Company's  management.  Our
responsibility  is to  express  an opinion  on these  financial  statements  and
financial statement schedule 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 the Company as of December 31, 2000
and MEHC  (Predecessor)  as of  December  31,  1999,  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 schedule,  when considered in relation
to the basic consolidated financial statements taken as a whole, presents fairly
in all material respects the information set forth therein.


DELOITTE & TOUCHE LLP
Des Moines, Iowa
January 18, 2001
(March 27, 2001 as to Notes 17 and 19.A.)

<PAGE>

MidAmerican Energy Holdings Company                                 Schedule I
Parent Company Only
Condensed Balance Sheets

As of December 31, 2000 and 1999
(In thousands)

                                                       2000              1999
                                                   -----------        ----------
ASSETS
Current Assets:

   Cash and cash equivalents................       $    8,223       $   240,938
                                                   -----------      -----------
     Total current assets...................            8,223           240,938

Investments in and advances to subsidiaries
   and joint ventures.......................        3,087,166         3,138,484
Equipment, net..............................           17,228            16,728
Excess of cost over fair value of net
   assets acquired, net.....................        1,216,550                 -
Deferred charges and other assets...........          166,287           158,887
                                                   ----------       -----------

Total assets................................       $4,495,454        $3,555,037
                                                   ==========        ==========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:

   Accounts payable and other accrued
     liabilities............................       $   54,073        $   82,055
   Short term debt..........................           85,000                 -
                                                   ----------        ----------
     Total current liabilities..............          139,073            82,055

Non-current liabilities.....................            6,435             6,435
Notes payable - affiliate...................          122,177           136,755
Parent company debt.........................        1,829,971         1,856,318
                                                   ----------        ----------

   Total liabilities........................        2,097,656         2,081,563
                                                   ----------        ----------

Deferred income.............................           34,874            28,886
Company-obligated mandatorily redeemable
   preferred securities of subsidiary
   trusts...................................          786,523           450,000

Stockholders' Equity:
Zero coupon convertible preferred stock -
   authorized 50,000 shares, no par value,
   34,563 shares outstanding at
   December 31, 2000........................                -                 -
Common stock -authorized 60,000 and 180,000
   shares, no par value;  9,281 and 82,980
   shares issued, 9,281 and 59,944 shares
   outstanding, at December 31, 2000 and
   1999, respectively........................               -                 -
Additional paid in capital...................       1,553,073         1,249,079
Retained earnings............................          81,257           507,726
Accumulated other comprehensive loss, net....         (57,929)          (12,029)
Treasury stock - 23,036 common shares at
   December 31, 1999 at cost.................               -          (750,188)
                                                   ----------       -----------
Total stockholders' equity...................       1,576,401           994,588
                                                   ----------       -----------

Total Liabilities and Stockholders' Equity...      $4,495,454        $3,555,037
                                                   ==========        ==========

The notes to the consolidated MEHC financial  statements are an integral part of
these financial statements.

<PAGE>

MidAmerican Energy Holdings Company                                   Schedule I
Parent Company Only (continued)
Condensed Statements of Operations

For the three years ended December 31, 2000
(In thousands)

                                                  2000        1999       1998
                                                  ----        ----       ----
Revenue:

Equity in undistributed earnings of
    subsidiary companies and joint ventures..   $390,194    $166,428   $205,049
Cash dividends and distributions from
    subsidiary companies and joint ventures..     96,342     345,430    179,782
Interest and other income....................     13,818      34,002     44,686
                                                --------    --------   --------

   Total revenues............................    500,354     545,860    429,517
                                                --------    --------   --------

Expenses:

General and administration...................     45,089      39,174     28,584
Depreciation and amortization................     25,716       1,088      1,943
Interest, net of capitalized interest........    141,891     163,589    132,250
                                                --------    --------   --------

   Total expenses............................    212,696     203,851    162,777
                                                ---------   --------   --------

Income before provision for income taxes.....    287,658     342,009    266,740
Provision for income taxes...................     84,285      93,475     93,265
                                                --------    --------   --------

Income before minority interest..............    203,373     248,534    173,475
Minority interest............................     70,804      31,863     35,963
                                                --------    --------   --------

Income before extraordinary items and cumulative
   effect of change in accounting principle..    132,569     216,671    137,512
Extraordinary items, net of tax..............                (49,441)    (7,146)
Cumulative effect of change in accounting
   principle, net of tax.....................          -           -     (3,363)
                                                --------    --------   --------
Net income available to common stockholders..   $132,569    $167,230   $127,003
                                                ========    ========   ========



The notes to the consolidated MEHC financial  statements are an integral part of
these financial statements.

<PAGE>

MidAmerican Energy Holdings Company                                   Schedule I
Parent Company Only (continued)
Condensed Statements of Cash Flows

For the three years ended December 31, 2000
(In thousands)

                                              2000         1999        1998
                                           ----------   ----------  ----------

Cash flows from operating activities..     $ (299,862)  $ (261,276) $ (219,705)
                                           ----------   ----------  ----------

Cash flows from investing activities:
Decrease (increase) in advances to
   and investments in subsidiaries
   and joint ventures.................        143,052      (53,215)   (103,494)
Acquisition of MEHC (Predecessor).....     (2,048,266)           -           -
Other.................................         28,458       (4,390)    (24,328)
                                           ----------    ---------    --------
Cash flows from investing activities..     (1,876,756)     (57,605)   (127,822)
                                           ----------    ---------    --------

Cash flows from financing activities:

Proceeds from issuance of common and
   preferred stock.....................     1,428,024            -           -
Proceeds from issuance of parent
   company debt........................             -            -   1,502,243
Proceeds from issuance of trust
   preferred securities................       454,772            -           -
Repayments of parent company debt......             -     (853,420)   (167,285)
Net proceeds from revolver.............        85,000            -           -
Purchase of treasury stock.............             -     (104,847)   (724,791)
Other..................................       (23,893)      (4,208)    (20,823)
                                            ---------    ---------   ----------

Cash flows from financing activities...     1,943,903     (962,475)    589,344
                                           ----------   ----------   ---------

Net increase (decrease) in cash and
   cash equivalents....................      (232,715)   (1,281,356)   241,817

Cash and cash equivalents at beginning
   of period...........................       240,938     1,522,294  1,280,477
                                           ------------  ---------- ----------

Cash and cash equivalents at end of
   period..............................     $   8,223    $  240,938 $1,522,294
                                            =========    ========== ==========

Supplemental disclosures:
Interest paid (net of amount
   capitalized)........................     $ 144,147    $  180,274  $ 104,350
                                            =========    ==========  =========

Income taxes paid......................     $  94,405    $  130,875  $  53,609
                                            =========    ==========  =========

The notes to the consolidated MEHC financial  statements are an integral part of
these financial statements.

<PAGE>
SIGNATURES

Pursuant to the  requirements of Section 13 or 15(d) of the Securities  Exchange
Act of 1934,  the  Registrant  has duly  caused  this report to be signed on its
behalf by the undersigned thereunto duly authorized, in the City of Omaha, State
of Nebraska, on this 30th day of March, 2001.

MIDAMERICAN ENERGY HOLDINGS COMPANY


           /s/ David L. Sokol
-------------------------------------
David L. Sokol
Chairman of the Board and

Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following  persons on behalf of the  Registrant and
in the capacities and on the dates indicated.

          Signature                                      Date
          ---------                                      ----

/s/  David L. Sokol*                                    March 30, 2001
-------------------
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and
Director


/s/  Gregory E. Abel*                                   March 30, 2001
--------------------
Gregory E. Abel
President, Chief Operating Officer and Director


/s/  Patrick J. Goodman*                                March 30, 2001
-----------------------
Patrick J. Goodman
Senior Vice President and
Chief Financial Officer


/s/  Edgar D. Aronson*                                  March 30, 2001
---------------------
Edgar D. Aronson
Director


/s/  Stanley J. Bright *                                March 30, 2001
----------------------
Stanley J. Bright
Director


/s/  Walter Scott, Jr.*                                 March 30, 2001
----------------------
Walter Scott, Jr.
Director


/s/  Marc D. Hamburg *                                  March 30, 2001
---------------------
Marc D. Hamburg
Director

<PAGE>
/s/  Warren Buffett*                                    March 30, 2001
-------------------
Warren Buffett
Director


/s/  John Boyer*                                        March 30, 2001
---------------
John Boyer
Director


/s/  W. David Scott*                                    March 30, 2001
-------------------
W. David Scott
Director


*By:/s/  Steven A. McArthur                             March 30, 2001
---------------------------
Steven A. McArthur
Attorney-in-Fact
<PAGE>

EXHIBIT INDEX

3.1      Restated Articles of Incorporation of the Company.

3.2      Bylaws of the Company.

4.2     Indenture  for the 6 1/4%  Convertible  Junior Subordinated  Debentures,
        dated as of April 1, 1996, among CalEnergy Company, Inc., as Issuer, and
        the Bank of New York, as Trustee  (incorporated  by reference to Exhibit
        4.3 to Amendment 1 to the Company's   Registration   Statement  on  Form
        S-3, Registration No. 333-08315).

 4.3    Indenture,  dated as of September 20, 1996, between the  Company and IBJ
        Schroder  Bank & Trust  Company,  as  trustee,  relating to $225,000,000
        principal  amount  of 9 1/2%  Senior  Notes  due  2006 (incorporated  by
        reference to Exhibit 4.1 to the Company's Registration Statement on Form
        S-3, Registration No. 333-15591).

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 1996 Form 10-K).

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,  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,  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,  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.

4.10     Subscription  Agreement executed by Berkshire Hathaway Inc. dated as of
         March 14, 2000.

10.1     Employment  Agreement between the Company and David L. Sokol, dated May
         10, 1999.

10.2     Amendment  No.  1 to  the  Amended  and  Restated  Employment Agreement
         between the Company and David L. Sokol, dated March 14, 2000.

10.3     Amended  and Restated  Employment  Agreement  between  the  Company and
         Gregory E. Abel, dated May 10, 1999.

10.4     Amended  and Restated  Employment  Agreement  between  the  Company and
         Steven A. McArthur, dated May 10, 1999.
<PAGE>
10.5     Employment  Agreement between the Company and Patrick J. Goodman, dated
         May 10, 1999.

10.9     125 MW Power Plant - Upper Mahiao  Agreement  (the "Upper  Mahiao ECA")
         dated  September 6, 1993 between  PNOC-Energy  Development  Corporation
         ("PNOC-EDC")  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 1994 Form 10-K).

10.10    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 1994 Form 10-K).

10.11    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 1994 Form
         10-K).

10.12    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 1994 Form 10-K).

10.13    Overseas  Private  Investment  Corporation  Contract of Insurance dated
         April 8, 1994  between the  Overseas  Private   Investment  Corporation
         ("OPIC") and the  Company  through its  subsidiaries  CE  International
         Ltd., CE Philippines  Ltd., and Ormat-Cebu Ltd. (incorporated by refer-
         ence to Exhibit 10.99 to the Company's 1994 Form 10-K).

10.14    180 MW Power Plant - Mahanagdong  Agreement  ("Mahanagdong  ECA") dated
         September  18, 1993 between  PNOC-EDC and CE  Philippines  Ltd. and the
         Company,  as amended by the First  Amendment to  Mahanagdong  ECA dated
         June 22, 1994,  the Letter  Agreement  dated July 12, 1994,  the Letter
         Agreement dated July 29, 1994, and the Fourth  Amendment to Mahanagdong
         ECA dated March 3, 1995 (incorporated by reference to Exhibit 10.100 to
         the Company's 1994 Form 10-K).

10.15    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 1994 Form 10-K).

10.16    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 1994 Form
         10-K).

10.17    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 1994 Form
         10-K).

10.18     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 1994 Form 10-K).
<PAGE>
10.19    Overseas Private  Investment  Corporation  Contract of  Insurance dated
         July 29, 1994 between OPIC 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 1994 Form 10-K).

10.20    231  MW  Power  Plant  -  Malitbog  Agreement  ("Malitbog  ECA")  dated
         September  10, 1993 between  PNOC-EDC  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 1994 Form 10-K).

10.21    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
         1994 Form 10-K).

10.22    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 1994 Form
         10-K).

10.23    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 1994 Form 10-K).

10.24    Overseas  Private  Investment  Corporation  Contract of Insurance dated
         December   21,  1994   between   OPIC  and  Magma   Netherlands,   B.V.
         (incorporated by reference to Exhibit 10.110 to the Company's 1994 Form
         10-K).

10.25    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, OPIC and the Banks named therein (incorporated by reference
         to Exhibit 10.111 to the Company's 1994 Form 10-K).

10.26    Trust  Indenture  dated as of November 27, 1995 between the CE Casecnan
         Water and Energy  Company,  Inc.  ("CE  Casecnan")  and Chemical  Trust
         Company of California  (incorporated  by reference to Exhibit 4.1 to CE
         Casecnan's  Registration  Statement on Form S-4 dated  January 25, 1996
         ("Casecnan S-4").

10.27    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 the
         Casecnan Form S-4).

10.28    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
         1996 Form 10-K).

10.29    Public Electricity Supply License (incorporated by reference to Exhibit
         10.131 to the Company's 1996 Form 10-K)

10.30    Second Tier Supply  Licenses to Supply  Electricity for England & Wales
         and  Scotland  (incorporated  by  reference  to  Exhibit  10.132 to the
         Company's 1996 Form 10-K).

10.31    Pooling  and  Settlement  Agreement  for the  Electricity  Industry  in
         England and Wales dated 30th March,  1990 (as amended at 17th  October,
         1996),  among The  Generators  (named  therein),  the Suppliers  (named
         therein),  Energy  Settlements  and  Information  Services  Limited (as
         Settlement  System  Administrator),  Energy  Pool Funds  Administration
         Limited (as Pool Funds Administrator),  Scottish Power plc, Electricite
         deFrance,  Service  National and Others  (incorporated  by reference to
         Exhibit 10.133 to the Company's 1996 Form 10-K).
<PAGE>
10.32    Master  Connection  and User System  Agreement with  The National  Grid
         Company  plc  (incorporated  by  reference to  Exhibit  10.134  to  the
         Company's 1996 Form 10-K).

10.33    Gas   Suppliers  License   dated  February 21,  1996  (incorporated  by
         reference to Exhibit 10.135 to the Company's 1996 Form 10-K).

10.34    Acquisition  Agreement  by and  between  CalEnergy  Company,  Inc.  and
         Kiewit  Diversified  Group Inc. dated as of September  10, 1997 (incor-
         porated by  reference to  Exhibit 2 to the  Company's Current Report on
         Form 8-K dated September 11, 1997).

10.35    Agreement and  Plan of  Merger dated as of August 11, 1998 by and among
         CalEnergy  Company,  Inc.,  Maverick  Reincorporation  Sub,  Inc., Mid-
         American  Energy  Holdings  Company  and  MAVH  Inc.  (incorporated  by
         reference to the  Company's Current Report on Form 8-K dated August 11
         1998).

10.36    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 1998 Form
         10-K).

10.37    Settlement  Agreement  by and  between MidAmerican  Energy Company, the
         Iowa Utilities Board, the Iowa Office of Consumer Advocate, and others.
         (incorporated by reference to the Company's 1998 Form 10-K).

10.38    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 Midwest  Resources  Inc.'s Annual Report on Form 10-K for the
         year ended December 31, 1992, Commission File No. 1-10654.)

10.39    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 Midwest
         Resources' Annual  Report on  Form 10-K for the year ended December 31,
         1992, Commission File No. 1-10654.)

10.40    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 Midwest
         Resources'  Annual Report on  Form 10-K for the year ended December 31,
         1992, Commission File No. 1-10654.)

10.41    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   Midwest
         Resources'  Annual  Report on Form 10-K for the year ended December 31,
         1993, Commission File No. 1-10654.)

10.42    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 Midwest  Resources' Annual
         Report on Form 10-K for the  year  ended December 31, 1994,  Commission
         File No. 1-10654.)

10.43    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 Midwest  Resources' Annual
         Report  on Form  10-K for  the year ended December 31, 1994, Commission
         File No. 1-10654.)
<PAGE>
10.44    Indenture  of  Mortgage  and Deed of Trust,  dated as of March 1, 1947.
         (incorporated  by  reference to  Iowa-Illinois Gas and Electric Company
         ("Iowa-Illinois") as Exhibit 7B to Commission File No. 2-6922.)

10.45    Sixth  Supplemental  Indenture dated as of July 1, 1967.  (incorporated
         by  reference  to Iowa-Illinois as  Exhibit 2.08 to Commission File No.
         2-28806.)

10.46    Twentieth Supplemental Indenture dated as of May 1, 1982. (incorporated
         by reference to Exhibit 4.B.23 to  Iowa-Illinois'  Quarterly  Report on
         Form 10-Q for  the  period  ended  June 30,  1982,  Commission File No.
         1-3573.)

10.47    Resignation and Appointment of successor Individual Trustee. (incorpor-
         ated by reference to Iowa-Illinois as Exhibit 4.B.30 to Commission File
         No. 33-39211.)

10.48    Twenty-Eighth Supplemental Indenture dated as of May 15, 1992.  (incor-
         porated by reference to Exhibit 4.31.B to Iowa-Illinois' Current Report
         on Form 8-K dated May 21, 1992, Commission File No. 1-3573.)

10.49    Twenty-Ninth Supplemental Indenture dated as of March 15, 1993. (incor-
         porated by reference to Exhibit 4.32.A to Iowa-Illinois' Current Report
         on Form 8-K dated March 24, 1993, Commission File No. 1-3573.)

10.50    Thirtieth Supplemental Indenture dated as of October  1, 1993.  (incor-
         porated by reference to Exhibit 4.34.A to Iowa-Illinois' Current Report
         on Form 8-K dated October 7, 1993, Commission File No. 1-3573.)

10.51    Sixth  Supplemental Indenture dated as of July 1, 1995, between Midwest
         Power Systems Inc. and Harris Trust and Savings Bank, Trustee.  (incor-
         porated by reference  to Exhibit 4.15 to  MidAmerican  Energy Company's
         ("MidAmerican  Energy") Annual Report on  Form 10-K  dated December 31,
         1995, Commission File No. 1-11505.)

10.52    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
         MidAmerican  Energy's  Annual  Report on Form 10-K dated  December  31,
         1995, Commission File No. 1-11505.)

10.53    Power Sales Contract  between Iowa Power Inc. and Nebraska Public Power
         District,  dated  September 22, 1967.  (incorporated  by  reference  to
         Exhibit 4-C-2 to Iowa Power Inc.'s (IPR) Registration Statement, Regis-
         tration No. 2-27681).

10.54    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  to  IPR's  Registration  Statement,  Registration  No.
         2-35624.)

10.55    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 to
         IPR's Registration Statement, Registration No. 2-42191.)

10.56    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 to
         IPR's Registration Statement, Registration No. 2-51540.)
<PAGE>
10.57    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 MidAmerican Energy's Quarterly Reports on the combined Form 10-Q for
         the quarter ended September 30, 1997, Commission File Nos.  1-12459 and
         1-11505, respectively.)

10.58    MidAmerican Energy Company Severance Plan For Specified Officers  dated
         November 1, 1996.  (incorporated  by reference to Exhibit  10.1 to Mid-
         American Energy's Annual Reports on the combined Form 10-K for the year
         ended  December  31, 1996,  Commission  File  Nos. 1-12459 and 1-11505
         respectively.)

10.59    MidAmerican  Energy  Holdings Company Executive Voluntary Deferred Com-
         pensation Plan.

10.60    MidAmerican Energy Company Supplemental  Retirement Plan for Designated
         Officers.  (incorporated  by  reference  to Exhibit 10.3 to MidAmerican
         Energy's Annual Report on Form 10-K dated December 31, 1995, Commission
         File No. 1-11505.)

10.61    MidAmerican  Energy  Company  Restated  Executive Deferred Compensation
         Plan.

10.62    MidAmerican Energy Holdings Company Restated Deferred Compensation Plan
         - Board of Directors.

10.63    MidAmerican  Energy Company Combined Midwest  Resources/Iowa  Resources
         Restated Deferred Compensation Plan - Board of Directors.

10.66    Midwest Resources Inc. Supplemental  Retirement Plan (formerly the Mid-
         west Energy Company  Supplemental  Retirement  Plan).  (incorporated by
         reference to Exhibit 10.10 to Midwest  Resources' Annual Report on Form
         10-K  for  the  year  ended  December  31,  1993,  Commission  File No.
         1-10654.)

10.72    Supplement Retirement  Plan for  Principal  Officers,  as amended as of
         July 1, 1993.  (incorporated  by  reference to Exhibit  10.K.2 to Iowa-
         Illinois' Annual  Report on Form 10-K  for  the year  ended December 31
         1993, Commission  File No. 1-3573.)

10.73    Compensation  Deferral Plan for  Principal  Officers,  as amended as of
         July 1, 1993.  (incorporated  by reference to Exhibit  10.K.2  to Iowa-
         Illinois'  Annual  Report on Form 10-K for the  year ended December 31,
         1993, Commission File No. 1-3573.)

10.74    Board  of  Directors'  Compensation  Deferral  Plan.  (incorporated  by
         reference  to  Exhibit  10.K.4 to  Iowa-Illinois' Annual Report on Form
         10-K for the year ended December 31, 1992, Commission File No. 1-3573.)

10.75    Amendment No. 1 to the Midwest  Resources Inc.  Supplemental Retirement
         Plan. (incorporated by reference to Exhibit 10.24 to Midwest Resources
         Annual  Report  on Form 10-K for the year ended December 31, 1994, Com-
         mission File No. 1-10654.)

10.78    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.
         to  MidAmerican  Energy's  Quarterly Reports on the combined  Form 10-Q
         for  the  quarter  ended  September  30,  1997,  Commission  File  Nos.
         1-12459 and 1-11505, respectively.)

21.0     Subsidiaries of Registrant.

23.0     Consent of Independent Auditors

24.0     Power of Attorney.