SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549

                                    FORM 10-K

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

                   For the fiscal year ended December 31, 1999
                           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 require-
ments 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 amendment 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, 2000, 9,281,087  shares of common
stock were outstanding.


<PAGE>



                                TABLE OF CONTENTS

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

 PART I........................................................................4
 Item 1.  Business.............................................................4
 General.......................................................................4
 Berkshire Transaction.........................................................4
 Strategy......................................................................4
        The Global Energy Market...............................................6
        The United States......................................................6
        The United Kingdom.....................................................8
 The Company's Distribution and Supply Business...............................10
        MidAmerican Energy Company............................................10
        Northern Electric.....................................................14
 The Company's Power Generation Project Portfolio.............................15
 Projects in Operation........................................................17
        United States Power Generation........................................17
        MidAmerican Energy Generation Facilities..............................17
        CE Generation Geothermal Facilities...................................18
        CE Generation Gas Facilities..........................................20
        Other U.S. Geothermal Interests.......................................21
        United Kingdom Power Generation.......................................21
        The Philippines Power Generation......................................22
 Projects in Construction.....................................................24
        United States.........................................................24
        Philippines...........................................................25
        United Kingdom........................................................26
Projects in Development.......................................................26
        United States.........................................................26
        United Kingdom........................................................27
 Producing Gas Field Operations and Fields in Development.....................27
        Producing Fields......................................................27
        Projects in Development...............................................27
 Other  ......................................................................29
        HomeServices..........................................................29
        Indonesia.............................................................29
 Regulatory, Energy and Environmental Matters.................................30
        United States.........................................................30
        United Kingdom........................................................31
 Employees....................................................................32
 Item 2.  Properties..........................................................32
 Item 3.  Legal Proceedings...................................................33
 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
 Management...................................................................35


                                      -2-
<PAGE>

 Item 10. Directors, Executive and Other Officers of the
          Company and Significant Subsidiaries......................... ......35
 Item 11. Executive Compensation..............................................40
 Item 12. Security Ownership of Certain Beneficial Owners and Management......40
 Item 13. Certain Relationships and Related Transactions......................40


 PART IV......................................................................41
 Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K....41

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

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



                                      -3-
<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, the Company manages, owns interests
in and has under contract  approximately  9,700 megawatts  ("MW") of diversified
power  generation  facilities in operation,  construction  and  development.  In
addition,  through its subsidiaries,  MidAmerican  Energy Company  ("MidAmerican
Energy" or "MEC") and Northern Electric plc ("Northern"),  the Company currently
serves  approximately 2.0 million electricity  customers and 1.2 million natural
gas  customers  worldwide.  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 Duff &
Phelps Credit Rating Company (DCR). The Company's utility  subsidiaries are also
investment grade rated by Moody's,  S&P and DCR:  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.

Berkshire 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 closed on the
acquisition on March 14, 2000.  Pursuant to the acquisition,  the Investor Group
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.

Strategy
--------

The Company's strategy remains focused on profit  enhancement  through operating
efficiencies while maintaining  quality and reliability of service and continued
diversification  of its assets by taking advantage of the investment  opportuni-
ties created by the continuing restructuring and privatization in energy sectors
in the United States and throughout the world.  In order to effectively  execute
its  strategy,  the Company  has  organized  its  operations  into a  functional
structure.  The  functional  alignment  is believed  to allow for greater  effi-
ciencies in operations and better  coordination and asset  utilization in devel-
oping the Company's business.

The Company's strategy is comprised of the following key elements:

o        Profit  Enhancement  through Operating  Efficiencies while  Maintaining
         Quality and  Reliability  of Service.  The Company aggressively pursues
         profitability improvements through efficiency and productivity gains at
         existing  operations.  The  cost of production  per kWh at the Imperial
         Valley Projects (as defined  herein) has declined from 5.3 cents/kWh in
         1994 to 2.6 cents/kWh in 1999. The Company has achieved these efficien-
         cies  while  maintaining high reliability and safety in its  operation.
         Through  continuing  advancements  in  drilling  technology,  reservoir
         modeling and well  maintenance  techniques, the production  capacity of
         new and  existing  wells  has  been  improved or  maintained  and, as a
         result,  the useful output of the various geothermal resources has been
         improved or maintained.

                                      -4-
<PAGE>

o        Continued Diversification of Revenue Base and Fuel  Sources.  The  Com-
         pany believes that it has a diversified revenue base, distributed among
         its ownership  of two  operating  electricity  and gas  utilities,  its
         ownership of interests in diversified  power generation facilities with
         10,260 net MW in  operation,  under  construction or in development and
         its ownership of producing  gas fields (all as described in more detail
         below).  In addition to the revenues of  MidAmerican Energy,  which are
         largely derived from the  generation,  transmission,  distribution  and
         sale of  electricity  and the  distribution and sale of gas activities,
         and Northern, which are largely  derived from their electricity distri-
         bution and gas supply  activities,  a portion of the Company's revenues
         are from its 50% equity  ownership  interest in CE  Generation, throug
         long-term contracts  between project  subsidiaries  and four large U.S.
         utility  companies, and the Company's subsidiaries' long-term contracts
         with the Government of the Philippines (sovereign  ratings of Ba1/BB+).
         The Company intends to seek  continued  diversification  of its revenu
         base and fuel sources through acquisitions and  greenfield development.

o        Growth through  International  and Domestic  Acquisitions.  The Company
         intends to continue to  opportunistically  engage in international  and
         domestic  acquisitions of energy projects and companies that support it
         long term investment strategy.

         The Company further  believes that the electricity  and gas industry in
         the U.S. will  progressively  restructure over the  next  three to five
         years and will  largely follow the  deregulatory  model  established in
         the U.K. (with  incentive  based rates  or price  caps).  As  currently
         regulated   U.S.  electricity  distributors  and  electricity  and  gas
         suppliers attempt to  rationalize  their  businesses  to maintain  pro-
         fitability  in a price competitive  market,  the Company  believes that
         opportunities  will  become  available to acquire low cost and reliabl
         providers of energy services to gain market share  in energy supply and
         provide additional services to competitors  (such as utility line  con-
         struction  and  maintenance  services,  metering, customer  billing and
         information systems services).

o        Growth through Greenfield Development of Energy  Projects.  The Company
         has commenced  construction  of a 537 MW  natural gas fired  generation
         facility  which  will  sell  power on a partial  contract  and  partial
         merchant  basis.  The facility is located near the Quad Cities in Illi-
         nois and Iowa on the border of two electric reliability districts,  the
         Mid-Continent.  Area  Power  Pool and  the Mid-America  Interconnection
         Network.  In  addition  to developing  domestic  energy  projects,  the
         Company continues to view the international  power generation sector as
         an attractive  market for  the  development  of new  greenfield  energy
         opportunities,  an  area  in  which  it  has  demonstrated  substantial
         expertise. With CalEnergy Gas (UK)Limited, the Company has expanded its
         development strategy to include integrated  upstream natural gas opera-
         tions.  The integration  of power  generation  plants with the upstream
         gas sources in  competitive  energy  markets will  also produce  market
         arbitrage  opportunities to  sell either gas or  electricity  depending
         upon market conditions at the time.

o        Maintenance of  Prudent Financial and Risk  Management  Practices.  The
         Company has consistently maintained, and intends in the future to main-
         tain  what  it  believes  to be  prudent  financial and risk management
         practices.  A primary  objective of the Company is to structure project
         financings for development projects which can be rated investment grade
         by Moody's, DCR and S&P. The Company's senior unsecured obligations are
         rated Baa3, BBB- and BBB-.  Its MidAmerican  Energy subsidiary is rated
         A3, A+ and A-; Salton Sea Funding Corp. is rated  Baa2/BBB;  CE Genera-
         tion LLC is rated Baa3, BBB and BBB-;  its Northern Electric subsidiary
         is rated A3, A and A-, and its CE Electric UK Funding  Company subsidi-
         ary's  senior  notes  are  rated  Baa1, A- and  BBB+.  The debt ratings
         reflected  above  have been  published by Moody's,  DCR (for all except
         Salton Sea Funding) and S&P, respectively, in respect of certain senior
         indebtedness of  the respective  issuers  shown.  These ratings  may be
         changed from  time to  time by the  ratings agencies.  The project fin-
         ancing structures  utilized to date by the Company  include as a funda-
         mental protection  for the Company's  other assets the requirement that
         (with certain minimal  exceptions) the funds borrowed and other obliga-
         tions  for  the  purpose of financing or operating  a project are to be
         primarily or entirely under loan  agreements,  project  agreements  and
         related
                                      -5-
<PAGE>

          documents  which  provide  that the  obligations  and  loans are to be
          performed  or repaid  solely  by the  project  and from the  project's
          revenues  and that the  security  granted to secure the loan and other
          obligations  be limited to the capital  stock,  assets,  contracts and
          cash flow of the project or the project  holding  company.  Under this
          type of structure,  the lenders and other project  contracting parties
          cannot seek recourse against the Company or its other  subsidiaries or
          projects.  The Company intends to continue to structure future project
          in a manner which minimizes the exposure of the Company's other assets
          through appropriate non-recourse project structures.

o        Continued Adherence to Strict Project Evaluation Criteria.  The Company
         intends to operate only in those countries where economic  fundamentals
         are believed to be attractive and risks can be contractually  mitigated
         or adequately overed by insurance.  The Company's international invest-
         ment  criteria  generally  includes  giving  due  consideration,  where
         appropriate, to the following:
               o    Sovereign guarantees;
               o    Significant demand for new power generating facilities;
               o    An established legal system providing for enforceability of
                    con- tracts and regulations;
               o    "Take or Pay" contracts with utilities, governments or other
                    parties with acceptable  creditworthiness  which provide for
                    pri- marily US$-denominated payments and certain contractual
                    protec-  tions   regarding   currency   convertibility   and
                    transferability;
               o    Fixed-price  date-certain,  turnkey  construction  contracts
                    with liquidated damages and performance security provisions;
                    and
               o    Availability of political risk insurance.

The  Company  intends to  continue  to focus  primarily  upon those  development
opportunities  where it is  permitted,  directly  or  indirectly,  to  acquire a
majority  ownership  interest  and exercise  operational  control over the newly
developed or acquired projects.

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.

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



                                      -6-
<PAGE>

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 and the
need for new generating capacity has been reduced.

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,  has  adopted  a  bill  to
restructure the electric industry by providing for a phased-in competitive power
generation industry,  with a power exchange and independent system operator, and
for direct  access to  generation  for all power  purchasers  outside  the power
exchange under certain circumstances. The bill provides 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,  respectively.  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.

In that regard,  in December  1999,  the Federal  Energy  Regulatory  Commission
issued Order No. 2000 establishing,  among other things, minimum characteristics
and functions for Regional  Transmission  Organizations (RTOs). Public utilities
not a member  of an  independent  system  operator  at the time of the order are
required  to  submit  a plan by  which  its  transmission  facilities  would  be
transferred  to an RTO on a  schedule  that  would  allow  the  RTO to  commence
operating by December 15, 2001. MidAmerican Energy, which was not a member of an
independent  system operator,  is presently  analyzing the impact that the order
may have on its operations.

In Illinois,  the electric retail business is opening up to competition and will
be phased in between October 1999 and May 2002. In Iowa,  legislation that would
restructure the electric utility business is being considered by the legislature
during its 2000 session.

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.

In Iowa, if MidAmerican Energy's annual electric jurisdictional return on common
equity exceeds 12%, then an equal sharing between  customers and shareholders of
earnings  above the 12% level  begins;  if it exceeds 14%,  then  two-thirds  of
MidAmerican  Energy's  share of  those  earnings  will be used  for  accelerated
recovery of certain  regulatory  assets.  MidAmerican  Energy is precluded  from
filing for  increased  rates  prior to 2001  unless the return on common  equity
falls below 9%. Other parties are prohibited from filing for reduced rates prior
to 2001  unless  the  return on  common  equity,  after  reflecting  credits  to
customers, exceeds 14%.

Prior to July 11,  1997,  MidAmerican  Energy was  allowed to recover its energy
costs from most of its electric  utility  customers  through  energy  adjustment
clauses.  Beginning  in  July  1997,  the  Iowa  energy  adjustment  clause  was
eliminated  as part of the Iowa  pricing  plan  approved  by the Iowa  Utilities
Board.  Accordingly,  flucuations  in energy  costs now may  affect  MidAmerican
Energy's earnings.


                                      -7-
<PAGE>

MidAmerican  Energy  provides gas service at retail  pursuant to non-  exclusive
municipal  franchises.  The cost of gas is recovered  from  customers  through a
purchased gas adjustment clause.

In connection  with the March 1999 approval by the Iowa  Utilities  Board of the
MidAmerican  Merger  and  recent  affirmation  as part of the  Investor  Group's
acquisition of the Company,  MidAmerican Energy is required, among other things,
to use all commercially reasonable efforts to maintain an investment grad credit
rating for MidAmerican Energy and its long-term debt and to seek the approval of
the  Iowa  Utilities  Board  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 circum- stances.
MidAmerican  Energy's  common  equity level at December 31, 1999 was above these
levels.

Statement of Financial  Accounting Standards (SFAS) No. 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.  A possible
consequence  of the  changes  in the  utility  industry  is the  discon-  tinued
applicability f SFAS 71. The majority of MidAmerican  Energy's  electric and gas
utility operations currently meet the criteria of SFAS 71, but its applicability
is periodically reexamined. If utility operations no longer meet the criteria of
SFAS  71,  MidAmerican  Energy  would  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.

The United Kingdom

The  electricity  industry in the United Kingdom has seen the  privatization  of
electric supply and distribution, and gradual phase-in of competition in supply,
since 1990. The Electricity Act of 1989  established an industry  structure that
permitted this phased-in  competition to occur.  Since that time, in England and
Wales, electricity is produced by generators,  the largest of which are National
Power,  PowerGen,   Eastern  Electricity  and  British  Energy.  Electricity  is
transmitted  through the national grid transmission  system by The National Grid
Company plc ("NGC") and distributed to customers by the twelve regional electric
companies  ("RECs")  in their  respective  authorized  areas.  The  majority  of
customers are supplied with  electricity by their local REC,  although there are
other suppliers  holding second tier supply licenses,  including  generators and
RECs, who can compete to supply customers in that REC's authorized area.  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.

Virtually all  electricity  generated in England and Wales is 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.

Distribution. Each  of the RECs 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 use of its distribution system, a
REC must not discriminate  between its own supply business and that of any other
authorized   electricity   operator,   or  between  those  of  other  authorized
electricity  operators;  nor may its charges  differ  except where  justified by
differences in cost.

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 REC is
entitled to charge.  The  distribution  price  control  formula  permits RECs 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 REC



                                      -8-
<PAGE>

from year to year. It is a control on revenue which  operates  independently  of
the REC'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  is to be
reduced by 24% with  effect from April 1, 2000.  As part of the  review,  the Xd
factor was not modified and therefore remains 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 certain  government  proposed  regulatory
incentive initiatives.

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 two types of licensed  suppliers:  public electricity supply ('PES" or
"first tier") suppliers and second tier suppliers.  PESs are the RECs,  Scottish
Power and  Hydro-Electric,  each  supplying in its respective  authorized  area.
Second tier suppliers include National Power, PowerGen, British Energy, Scottish
Power,   Hydro-Electric  and  other  PESs  supplying  outside  their  respective
authorized areas. There are also a number of independent second tier suppliers.

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  will be
required  to reduce  its  prices to most of its  domestic  customers  within its
authorized area by about 11% from April 1, 2000.

The Pool. 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  are 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.

The price control  regulations  which govern the  authorized  area supply market
permit the pass-through to customers of certain  permitted costs,  which include
the cost of  arrangements  such as CFDs to hedge against Pool price  volatility.
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.

                                      -9-
<PAGE>

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.  In addition,  the
United Kingdom  government has announced  plans to reform the wholesale  trading
market  for  electricity  by  eliminating  the Pool  and  creating  a  bilateral
wholesale trading market. The announced date for elimination of the Pool and the
introduction of the New Electricity Trading Arrangements ("NETA") is October 31,
2000. 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.

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.

The Company's Distribution and Supply Business

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

MidAmerican Energy Company

MidAmerican  Energy is the largest energy company  headquartered  in Iowa,  with
assets and 1999 revenues  totaling $3.6 billion and $1.8 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 distributes electric energy 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, 1999,
MidAmerican  Energy had 663,500  retail  electric  customers and 638,000  retail
natural gas customers.

In addition to retail sales,  MidAmerican  Energy delivers  electricity to other
utilities,  marketers and municipalities that distribute it to end-use customers
(sales for resale or off-system  sales) and  transports  natural gas, for a fee,
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 5% of its total 1999  electric  operating  revenues or 3% of its total
1999 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, 1999,  MidAmerican Energy derived  approximately
66% of its gross operating revenues from its regulated  electric  business,  and
25% from its  regulated  gas  business  and 9% from  its  nonregulated  business
activities.  For 1998 and 1997, the corresponding percentages were 69% electric,
25% gas and 6%  nonregulated;  and 65% electric and 31% gas and 4% nonregulated,
respectively.

                                      -10-
<PAGE>

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  will 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.

Although  specific  functions  may be moved  between  business  units as  future
circumstances   warrant,   the  main  focus  of  each  business  unit  has  been
established.  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 and conducts related
activities.  Retail includes  marketing,  customer service and related functions
for core and complementary products and services.

          Total Electric Sales of MidAmerican Energy By Customer Class

                                                1999       1998        1997

Residential                                     21.0%      22.2%       20.9%
Small General Service                           16.7       17.5        16.5
Large General Service                           26.9       28.1        27.4
Other                                            4.5        4.4         4.4
Sales for Resale                                30.9       27.8        30.8
                                               -----      -----       -----
Total                                          100.0%     100.0%      100.0%
                                               =====      =====       =====


                                      -11-
<PAGE>

              Retail Electric Sales of MidAmerican Energy By State


                                              1999         1998        1997

Iowa                                          88.9%        88.4%       88.6%
Illinois                                      10.4         10.9        10.7
South Dakota                                   0.7          0.7         0.7
                                             -----        -----       -----
Total                                        100.0%       100.0%      100.0%
                                             =====        =====       =====

In an Iowa  pricing  settlement  approved in 1997 by the Iowa  Utilities  Board,
MidAmerican Energy was given permission to negotiate  individual  contracts with
its industrial  and  commercial  electric  customers.  The  negotiated  electric
contracts have differing  terms and conditions as well as prices.  The contracts
range in length from five to ten years,  and some have price  renegotiation  and
early termination  provisions  exercisable by either party. The vast majority of
the  contracts  are for  terms of  seven  years or  less,  although  some  large
customers  have  agreed to 10-year  contracts.  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
these contracts are approximately $180 million.

In addition,  MidAmerican  Energy is precluded by the 1997 settlement  agreement
from filing for an increase in its Iowa electric rates prior to 2001, unless its
annual  return on common equity falls below 9%.  Likewise,  the other parties to
the agreement are prohibited  from seeking a reduction in  MidAmerican  Energy's
electric rates prior to 2001,  unless the return on common equity,  adjusted for
the equal sharing  between  shareholders  and customers of earnings  above a 12%
return on common equity, exceeds 14%.

Under a  restructuring  law enacted in 1997, a similar  sharing  mechanism is in
place for Illinois operations. Two-year average returns on common equity greater
than a two year average  benchmark  will trigger an equal sharing of earnings on
the excess.  The benchmark is a  calculation  of average  30-year  Treasury Bond
rates plus 5.5% for 1998 and 1999 and 8.5% for 2000  through  2004.  The initial
calculation, due March 31, 2000, will be based on 1998 and 1999 results.

In Illinois beginning October 1, 1999, larger non-residential  customers and 33%
of the remaining  non-residential customers are allowed to select their provider
of electric  supply  services.  All other  non-residential  customers  will have
supplier choice starting  December 31, 2000.  Residential  customers all receive
the opportunity to select their electric supplier on May 1, 2002.

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:



                                      -12-
<PAGE>

        Total Regulated Gas Sales of MidAmerican Energy By Customer Class


                                            1999           1998          1997

Residential                                 62.0%          59.9%         60.8%
Small General Service                       31.4           32.1          33.1
Large General Service                        3.9            3.7           4.2
Sales for Resale and Other                   2.7            4.3           1.9
                                           -----          -----         -----
Total                                      100.0%         100.0%        100.0%
                                           =====          =====         =====

                 Retail Gas Sales of MidAmerican Energy By State

                                            1999           1998          1997

Iowa                                        78.8%          79.0%         79.1%
Illinois                                    10.3           10.2          10.4
South Dakota                                10.1           10.1           9.8
Nebraska                                     0.8            0.7           0.7
                                           -----          -----         -----
Total                                      100.0%         100.0%        100.0%
                                           =====          =====         =====

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 1999, 39% of MidAmerican Energy's electric revenues
were  reported in the months of June,  July,  August and  September,  and 55% 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
July 1999,  MidAmerican Energy recorded an hourly peak demand of 3,833 MW, which
is 190 MW more than MidAmerican Energy's previous record hourly peak of 3,643 MW
set in 1998.

MidAmerican Energy's accredited net generating  capability in the summer of 1999
was 4,466 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 certain 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,  serves as a power and energy
market  clearing house 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 for 1999 was approximately 16.5%.

                                      -13-
<PAGE>

Northern Electric

Northern Electric Distribution Limited ("Northern  Distribution"),  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. Northern Distribution 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, 1999,  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 24,000 transformers and approximately 23,000 substations.

Northern  Electric  Supply  Limited  ("Northern  Supply")  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,  primarily
from the Pool, and subsequent sale to individual customers.

Under the terms of its PES license,  Northern currently  supplies  approximately
1.5  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 provide electricity
to supply customers outside its authorized area.  Northern is one of the largest
suppliers to major users in the competitive and open  electricity  market in the
United  Kingdom and supplies  customers in all 15 PES areas in Great Britain and
Northern Ireland.

               Total Electric Sales of Northern By Customer Class

                                           1999           1998          1997

Residential                                27.5%          32.4%         34.0%
Small General Service                      12.7           16.2          16.7
Large General Service                      58.1           49.9          47.7
Sales for Resale and Other                  1.7            1.5           1.6
                                          -----          -----         -----
Total                                     100.0%         100.0%        100.0%
                                          =====          =====         =====

Northern  Supply also  competes to supply gas inside and outside its  authorized
area.  At December 31, 1999,  Northern  supplied  gas to  approximately  567,000
customers.

                  Total Gas Sales of Northern By Customer Class

                                           1999           1998         1997

Residential                                70.0%          45.5%        14.5%
Commercial                                 30.0           54.5         85.5
                                          -----          -----        -----
Total                                     100.0%         100.0%       100.0%
                                          =====          =====        =====

                                      -14-
<PAGE>

Northern Utility Services Limited ("Northern Utility") is an engineering company
whose  role is to adapt,  maintain  and  restore  the  distribution  network  of
Northern and to sell related  services to third  parties.  Northern  Utility has
been able to make  significant cost reductions for Northern during the past year
by working with  suppliers in order to improve core  processes,  close  selected
depot  locations,  increase  staff  productivity  and reduce  material and plant
costs.  Northern Utility has pioneered  techniques  using innovative  diagnostic
testing  equipment  which  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. Also, the continued  development
in the use of trenchless technology has brought both financial and environmental
benefits  to  Northern  and its  customers.  While  Northern  Utility's  largest
customer is Northern  Distribution,  it currently sells approximately 19% of its
services to third parties. Northern Utility is Northern's largest employer.

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.  Northern
Metering has developed an energy profiling system which helps businesses  reduce
costs through the more efficient use of all fuels, not just electricity.

THE COMPANY'S POWER GENERATION PROJECT PORTFOLIO
------------------------------------------------

The Company has ownership  interests in generating  facilities with an aggregate
of (i) 9,468 net MW in projects  in  operation  representing  an  aggregate  net
capacity owned of 5,195 net MW of electric generating capacity,  (ii) 746 net MW
in four projects under  construction  representing  an aggregate net capacity of
672 net MW  owned  electric  generating  capacity  and  (iii) 46 net MW in three
projects in advanced  development  stages with signed power sales  agreements or
under  award  representing  an  aggregate  net  capacity  owned  of 45 net MW of
electric generating capacity.


                                      -15-
<PAGE>
The following  tables set out certain  information  concerning  various  Company
projects in operation,  under construction and in development pursuant to signed
power sales agreements or awarded mandates.

<TABLE>
<CAPTION>
                               Facility     Net                                                                          Political
                                 Net        MW                                    Commercial   U.S. $     Power           Risk
 Project (1)                     MW       Owned (2)    Fuel     Location          Operation    Payments   Purchaser (3)  Insurance
 -----------                   --------   ---------   -----     --------          -----------  --------   -------------  ---------

<S>                              <C>       <C>        <C>         <C>             <C>           <C>         <C>          <C>
Projects in Operation
---------------------

Council Bluffs Energy            131       131        Coal        Iowa            1954, 1958    Yes         MEC          No
  Center units 1 & 2

Council Bluffs Energy            675       534        Coal        Iowa            1978          Yes         MEC          No

Louisa Generation Station        700       616        Coal        Iowa            1983          Yes         MEC          No

Neal Generation Station
  Units 1 & 2                    435       435        Coal        Iowa            1964, 1972    Yes         MEC          No

Neal Generation Station
  Station Unit 3                 515       371        Coal        Iowa            1975          Yes         MEC          No

Neal Generation Station
  Unit 4                         624       253        Coal        Iowa            1979          Yes         MEC          No

Ottumwa Generation Station       716       372        Coal        Iowa            1981          Yes         MEC          No

Quad-Cities Power Station      1,529       382        Nuclear     Illinois        1972          Yes         MEC          No

Riverside Generation
  Station                        135       135        Coal        Iowa            1925-61       Yes         MEC          No

Combustion Turbines              789       789        Gas         Iowa            1969-95       Yes         MEC          No

Moline Water Power                 3         3        Hydro       Illinois        1970          Yes         MEC          No

Imperial Valley                  268       134        Geo         California      1986-96       Yes         Edison       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     Yes

Malitbog                         216       216        Geo         Philippines     1996-97       Yes         PNOC-EDC     Yes

Upper Mahiao                     119       119        Geo         Philippines     1996          Yes         PNOC-EDC     Yes

Teesside Power Ltd             1,875       289        Gas         England         1993          No          Various      No

Viking                            50        25        Gas         England         1998          No          Northern     No
                               -----     -----

Total Projects in Operation    9,468     5,195
                               =====     =====
</TABLE>

----------

(1)  The Company  operates all such projects  other than Teesside Power Limited,
     Quad Cities Power Station, Ottumwa Generation Station and 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"); Northern Electric plc
     ("Northern"); Zinc Recovery Project ("Zinc") and MidAmerican Energy Company
     ("MEC").

                                      -16-
<PAGE>
<TABLE>
<CAPTION>

                               Facility     Net                                                                          Political
                                 Net        MW                                    Commercial   U.S. $     Power           Risk
Project (1)                      MW       Owned (2)    Fuel     Location          Operation    Payments   Purchaser (3)  Insurance
-----------                   --------   ---------   -----     --------          -----------  --------   -------------  ---------
<S>                           <C>        <C>          <C>       <C>                  <C>         <C>         <C>          <C>
Projects Under Construction
---------------------------

Casecnan                         150       105        Hydro     Philippines          2001        Yes         NIA GOP      Yes

Salton Sea V                      49        25        Geo       California           2000        Yes         Zinc/TBD     No

CE Turbo                          10         5        Geo       California           2000        Yes         Zinc/TBD     No

Cordova                          537       537        Gas       Illinois             2001        Yes         TBD          No
                              ------     -----
Total Projects Under
Construction                     746       672
                              ------     -----

Development Projects (4)
------------------------

Telephone Flat                    44        44        Geo       California           2001        Yes         BPA          No

Kirkheaton Wind Ltd.               2         1        Wind      England              2000        No          Northern     No
                              ------     -----
Total Development Projects        46        45
                              ------     -----

Total Power Generation

Projects                      10,260     5,912
                              ======     =====
</TABLE>


(1)  The Company  operates all such projects  other than Teesside Power Limited,
     Quad Cities Power Station, Ottumwa Generation Station and 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"); Northern Electric plc
     ("Northern"); Zinc Recovery Project ("Zinc") and MidAmerican Energy Company
     ("MEC").

(4)  Significant   contingencies  exist  in  respect  of  development  projects,
     including without  limitation,  the need to obtain  financing,  permits and
     licenses, and the completion of construction.  The Company is also pursuing
     a number of other power  projects  that are in more  preliminary  stages of
     development.

PROJECTS IN OPERATION
---------------------

UNITED STATES POWER GENERATION

MIDAMERICAN ENERGY GENERATION FACILITIES

All of the coal-fired  generating  stations  operated by MidAmerican  Energy are
fueled  primarily  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 acid rain provisions of the Clean Air Act Amendments ("CAAA")
without having to install  additional  costly emissions control equipment at its
generating  stations.   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.

                                      -17-

<PAGE>

MidAmerican  Energy  uses  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 the UP and to Council Bluffs Energy Center  ("CBEC") by the UP and the
BNSF.  Coal for  MidAmerican  Energy's  Louisa and Riverside  Energy  Centers is
delivered  to an  interchange  point  by  the  BNSF  for  transportation  to its
destination by the I&M Rail Link.  Competitive  rail access is available to CBEC
and to interchange points for deliveries to Louisa and Riverside Energy Centers.
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  Nuclear Power  Station.
MidAmerican Energy has been advised by Commonwealth Edison ("ComEd"),  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.  ComEd  foresees  no
problem  in  obtaining  the  remaining  requirements  now  or  obtaining  future
requirements.  ComEd further advises that all enrichment  requirements have been
contracted through 2003.  Commitments for fuel fabrication have been obtained at
least through 2005.  ComEd 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.

CE Generation Geothermal Facilities

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

Vulcan.  The Vulcan  Project sells  electricity  to Southern  California  Edison
Company  ("Edison")  under a  30-year  Standard  Offer  No.  4  Agreement  ("SO4
Agreement")  that  commenced  on February  10,  1986.  The Vulcan  Project has a
contract  capacity  and contract  nameplate of 29.5 MW and 34 MW,  respectively.
Under  the SO4  Agreement,  Edison  is  obligated  to pay the  Vulcan  Project a
capacity payment, a capacity bonus payment and an energy payment.  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  increased each year for the
first ten years,  which  period  expired on  February 9, 1996.  Thereafter,  the
energy payments are based on Edison's Avoided Cost of Energy.

Hoch (Del Ranch). The Hoch (Del Ranch) Project sells electricity to Edison under
a 30-year SO4 Agreement that commenced on January 2, 1989. The contract capacity
and contract nameplate are 34 MW and 38 MW, respectively. The provisions of such
SO4 Agreement are  substantially  the same as the SO4 Agreement  with respect to
the Vulcan Project.  The price for contract  capacity  payments is fixed for the
life of the SO4  Agreement.  The fixed price period for energy  payments per kWh
expired  on  January  1, 1999.  Thereafter,  the  energy  payments  are based on
Edison's Avoided Cost of Energy.

Elmore.  The Elmore  Project  sells  electricity  to Edison  under a 30-year SO4
Agreement that commenced on January 1, 1989. The contract  capacity and contract
nameplate  are 34 MW and  38  MW,  respectively.  The  provisions  of  such  SO4
Agreement are  substantially  the same as the SO4 Agreement  with respect to the
Vulcan Project.  The price for contract  capacity payments is fixed for the life
of SO4 Agreement.  The fixed price period for energy payments per kWh expired on
December 31, 1998. Thereafter, the energy payments are based on Edison's Avoided
Cost of Energy.

                                      -18-
<PAGE>

Leathers. The Leathers Project sells electricity to Edison pursuant to a 30-year
SO4  Agreement  that  commenced on January 1, 1990.  The  contract  capacity and
contract nameplate are 34 MW and 38 MW, respectively. The provisions of such SO4
Agreement are  substantially  the same as the SO4 Agreement  with respect to the
Vulcan Project.  The price for contract  capacity payments is fixed for the life
of SO4  Agreement  which  expired on December 31, 1999.  Thereafter,  the energy
payments will be based on Edison's Avoided Cost of Energy.

Salton Sea I  Project.  The Salton  Sea I Project  sells  electricity  to Edison
pursuant to a 30-year  negotiated  power  purchase  agreement,  as amended  (the
"Salton Sea I PPA"),  which provides capacity and energy payments.  The contract
capacity and contract nameplate are each 10 MW. The capacity payment is based on
the firm  capacity  price that is currently  $132.58 per  kW-year.  The contract
capacity  payment adjusts  quarterly based on a basket of energy indices for the
term of the Salton  Sea I PPA.  The energy  payment is  calculated  using a Base
Price  (defined as the initial value of the energy  payment (4.701 cents per kWh
for the  second  quarter of 1992)),  which is subject to  quarterly  adjustments
based on a basket of indices.  The time period  weighted  average energy payment
for Salton Sea I was 5.3 cents per kWh during  1999.  As the Salton Sea I PPA is
not an SO4 Agreement, the energy payments do not revert to Edison's Avoided Cost
of Energy.

Salton Sea II Project.  The Salton Sea II Project  sells  electricity  to Edison
pursuant to a 30-year  modified SO4 Agreement  that  commenced on April 5, 1990.
The contract  capacity and contract  nameplate are 15 MW (16.5 MW during on-peak
periods) and 20 MW, respectively.  The contract requires Edison to make capacity
payments,  capacity bonus payments and energy  payments.  The price for contract
capacity  and  contract  capacity  bonus  payments  is fixed for the life of the
modified SO4 Agreement. The energy payments for the first ten-year period, which
period expires on April 4, 2000, are levelized at a time period weighted average
of 10.6 cents per kWh. Thereafter,  the monthly energy payments will be Edison's
Avoided  Cost of Energy.  Edison is entitled to receive,  at no cost,  5% of all
energy  delivered in excess of 80% of contract  capacity  through  September 30,
2004.

Salton Sea III Project.  The Salton Sea III Project sells  electricity to Edison
pursuant to a 30-year  modified  SO4  Agreement  that  commenced on February 13,
1989.  The contract  capacity is 47.5 MW and the contract  nameplate is 49.8 MW.
The SO4 Agreement  requires  Edison to make capacity  payments,  capacity  bonus
payments and energy  payments for the life of the SO4  Agreement.  The price for
contract capacity payments is fixed at $175/kW per year. The energy payments for
the first  ten-year  period,  which period  expired on February  12, 1999,  were
levelized at a time period  weighted  average of 9.8 cents per kWh.  Thereafter,
the monthly energy payments are Edison's Avoided Cost of Energy.

Salton Sea IV Project.  The Salton Sea IV Project  sells  electricity  to Edison
pursuant to a modified  SO4  agreement  which  provides  for  contract  capacity
payments  on 34 MW of capacity at two  different  rates based on the  respective
contract  capacities deemed attributable to the original Salton Sea I PPA option
(20 MW) and to the original  Salton Sea IV SO4  Agreement  ("Fish Lake PPA") (14
MW). The capacity  payment price for the 20 MW portion  adjusts  quarterly based
upon specified indices and the capacity payment price for the 14 MW portion is a
fixed  levelized  rate. The energy payment (for  deliveries up to a rate of 39.6
MW) is at a fixed price for 55.6% of the total energy delivered by Salton Sea IV
and is based on an  energy  payment  schedule  for  44.4%  of the  total  energy
delivered  by Salton Sea IV. The  contract  has a 30-year term but Edison is not
required to purchase the 20 MW of capacity and energy originally attributable to
the Salton Sea I PPA option after  September 30, 2017, the original  termination
date of the Salton Sea I PPA.

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)  and  previously  operated the NorCon natural gas plant
(the "NorCon  Project").  (The Saranac Project,  Power Resources  Project,  Yuma
Project and NorCon Project are collectively referred to as the "Gas Plants").

                                      -19-
<PAGE>

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  energy is sold at  SDG&E's  Avoided  Cost of Energy and the
capacity  is sold to SDG&E at a fixed  price for the life of the Yuma  PPA.  The
power is wheeled  to SDG&E  over  transmission  lines  constructed  and owned by
Arizona Public Service Company ("APS").  The Yuma Project  commenced  commercial
operation in May 1994. 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") and as PURPA.  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. A natural gas supply and  transportation  agreement has been executed with
Southwest Gas Corporation, terminable under certain circumstances by the YCA and
Southwest Gas Corporation.

Saranac  Project.  The  Saranac  Project  is a  240  net  MW  natural  gas-fired
cogeneration  facility located in Plattsburgh,  New York, which began commercial
operation in June 1994.  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").

On February  14, 1995,  NYSEG filed with the FERC a Petition  for a  Declaratory
Order,  Complaint,  and  Request  for  Modification  of Rates in Power  Purchase
Agreements  Imposed  Pursuant to the Public Utility  Regulatory  Policies Act of
1978  ("Petition")  seeking  FERC (i) to declare that the rates NYSEG pays under
the Saranac PPA,  which was approved by the New York Public  Service  Commission
(the  "PSC"),  were in  excess of the level  permitted  under  PURPA and (ii) to
authorize  the PSC to reform the  Saranac  PPA. On March 14,  1995,  the Saranac
Partnership intervened in opposition to the Petition asserting, inter alia, that
the Saranac PPA fully complied with PURPA,  that NYSEG's action was untimely and
that the FERC lacked authority to modify the Saranac PPA. On March 15, 1995, the
Company  intervened  also in  opposition  to the Petition  and asserted  similar
arguments.  On April 12, 1995, the FERC by a unanimous  (5-0) decision issued an
order  denying the various  forms of relief  requested by NYSEG and finding that
the rates  required  under the  Saranac PPA were  consistent  with PURPA and the
FERC's regulations. On May 11, 1995, NYSEG requested rehearing of the order and,
by order  issued  July 19,  1995,  the FERC  unanimously  (5-0)  denied  NYSEG's
request.  On June 14, 1995,  NYSEG petitioned the United States Court of Appeals
for the  District of Columbia  Circuit  (the "Court of  Appeals")  for review of
FERC's April 12, 1995 order.  FERC moved to dismiss NYSEG's  petition for review
on July 28,  1995.  On July 11,  1997,  the Court of Appeals  dismissed  NYSEG's
appeal from FERC's denial of the petition on jurisdictional grounds.

On August 7, 1997,  NYSEG filed a complaint in the U.S.  District  Court for the
Northern  District  of New York  against  the FERC,  the PSC (and the  Chairman,
Deputy  Chairman  and the  Commissioners  of the  PSC as  individuals  in  their
official capacity), the Saranac Partnership and Lockport Energy Associates, L.P.
("Lockport")  concerning the power purchase  agreements  that NYSEG entered into
with Saranac  Partners and  Lockport.  NYSEG's suit asserts that the PSC and the
FERC improperly  implemented  PURPA in authorizing the pricing terms that NYSEG,
the Saranac  Partnership and Lockport agreed to in those  contracts.  The action
raises  similar legal  arguments to those  rejected by the FERC in its April and
July 1995 orders.  NYSEG in addition  asks for  retroactive  reformation  of the
contracts  as of the date of  commercial  operation  and  seeks a refund of $281
million from the Saranac Partnership.
                                      -20-
<PAGE>

The Saranac Partnership and other parties have filed motions to dismiss and oral
arguments  on those  motions  were  heard on March 2, 1998 and again on March 3,
1999. The Saranac Partnership believes that NYSEG's claims are without merit for
the same reasons described in the FERC's orders.

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  began  commercial
operation  in June 1988.  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 Gas Supply
Agreement  contains  rates  that are fixed for the  respective  contract  terms.
Revenues escalate at a higher rate than fuel costs.

NorCon  Project.   The  NorCon  Project  is  an  80  net  MW  natural  gas-fired
cogeneration facility located in North East, Pennsylvania which began commercial
operation in December  1992.  The NorCon  Project had a 25-year  power  purchase
agreement (the "NorCon PPA") with Niagara Mohawk Power Corporation  ("NIMO"). On
December 2, 1999, the NorCon Project was  transferred to GECC and the NorCon PPA
was terminated. The Company no longer retains an interest in the NorCon Project.

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.

United Kingdom Power Generation

In the United  Kingdom,  a Northern  subsidiary,  Northern  Electric  Generation
Limited ("Northern  Generation"),  focuses on electricity generation,  primarily
through its  ownership  in Teesside  (described  herein) and its  operation  and
ownership  of  Viking  (described  herein).  Northern  Generation  also owns and
operates a 5 MW diesel power generating plant located in Northallerton, England.

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.

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  2001.  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

                                      -21-
<PAGE>

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 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.

Upon completion of the transmission line, the construction loan was converted to
a term loan in May 1998.  Export-Import Bank of the United States ("Ex-Im Bank")
and United  Coconut  Planters  Bank of the  Philippines  are  providing the term
loans.

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  Corporaiton
("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.

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,  although its output was constrained  until early
1998 because the required full  transmission  line was not completed  until that
time. 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. During

                                      -22-
<PAGE>

the period of  constrained  operation,  PNOC-EDC  was  required to, and paid all
capacity fees under the take or pay provisions of the contract.

Upon completion of the transmission line, the construction loan was converted to
a term loan in June 1998.  The project  financing term loan is being provided by
OPIC and Ex-Im Bank.

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  expected  to be  approximately  97% of total  revenues  at the  design
capacity levels and the energy fees are expected to be  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),  although  as with the Upper
Mahiao and Mahanagdong projects,  operation was constrained due to a lack of the
necessary   transmission   line.  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.

Upon completion of the transmission line, the construction loan was converted to
a term loan in April 1998.  A  consortium  of  international  banks and OPIC are
providing the term loan facilities.

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 thenet  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).

The  Malitbog  ECA  cooperation  period  will expire ten years after the date of
commencement of commercial  operation of Unit III. 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.  The capacity
fees are 100% of total revenues and there is no energy fee.

                                      -23-
<PAGE>

Projects in Construction
------------------------

United States

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"). Four facilities will be
installed near Imperial Valley Project sites to extract a zinc chloride solution
from  the  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
tonnes per year and is scheduled to commence  commercial  operation in mid-2000.
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.

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
internationally  recognized 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.  The Zinc  Recovery  Project is  scheduled  to commence  initial
operations in mid-2000.

Salton Sea V. Salton Sea Power LLC, an indirect  wholly owned  subsidiary  of CE
Generation,  is constructing the Salton Sea V Project.  The Salton Sea V Project
is a 49 net MW geothermal power plant which will sell approximately one-third of
its net output to the Zinc Recovery Project.  The remainder will be sold through
the California  Power Exchange ("PX") or other market  transactions.  The Salton
Sea V Project is being  constructed  pursuant to a date  certain,  fixed  price,
turnkey  engineering,  procurement and construction  contract (the "Salton Sea V
EPC Contract") by Stone & Webster Engineering  Corporation ("SWEC").  The Salton
Sea V Project is schedule to commence commercial operation in mid-2000.

CE Turbo. CE Turbo LLC, an indirect wholly-owned subsidiary of CE Generation, is
constructing the CE Turbo Project.  The CE Turbo Project will have a capacity of
10 net MW.  The net  output  of the CE  Turbo  Project  will be sold to the Zinc
Recovery  Project  or sold  through  the PX or  other  market  transactions.  In
addition to the CE Turbo Project,  the Partnership  Projects are constructing an
upgrade to the  geothermal  brine  processing  facilities  at the Vulcan and Del
Ranch Projects to incorporate  the pH  Modification  Process,  which has reduced
operating  costs at the Imperial  Valley  Project.  The CE Turbo Project and the
brine facilities  construction are being  constructed by SWEC pursuant to a date
certain, fixed price, turnkey engineering, procurement and construction contract
(the  "Region 2 Upgrade EPC  Contract").  The CE Turbo  Project is  scheduled to
commence  initial  operations  in  mid-2000  and the  Region 2 Brine  Facilities
Construction is scheduled to be completed in mid-2000.

Cordova.   Cordova  Energy  Company  LLC  ("Cordova  Energy"),  a  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 is being  constructed by SWEC
pursuant to a date certain,  fixed price, turnkey  engineering,  procurement and
construction contract.  Cordova is scheduled to commence commercial operation in
mid-2001.


                                      -24-
<PAGE>

Philippines

Casecnan.  In November  1995,  the Company  closed the  financing  and commenced
construction  of 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.  The
Casecnan Project will consist generally of diversion  structures in the Casecnan
and Taan (Denip) Rivers that will divert water into a tunnel of approximately 23
kilometers.  The  tunnel  will  transfer  the water from the  Casecnan  and Taan
(Denip) Rivers into the Pantabangan  Reservoir for irrigation and  hydroelectric
use in the Central Luzon area. An underground  powerhouse  located at the end of
the water tunnel and before the  Pantabangan  Reservoir will house a power plant
consisting of approximately 150 MW of newly installed rated electrical capacity.
A tailrace 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 of two downstream existing hydroelectric facilities of the NPC.

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,
is  developing  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 guaranteed  fee for the delivery of water
and a guaranteed fee for the delivery of  electricity,  regardless of the amount
of water or electricity actually delivered.  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 guaranteed  fees for the delivery of
water and energy are  expected  to provide  approximately  70% of CE  Casecnan's
revenues.

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.  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.

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.

CE Casecnan  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.

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. Accordingly, the Casecnan Project is now expected to become operational by
the second quarter of 2001.


                                      -25-
<PAGE>

Under the Project Agreement, if NIA has completed certain work on its irrigation
system, CE Casecnan is liable to pay NIA $5,000 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.

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.  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  substantially
denominated in United States  dollars and 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.

United Kingdom

Northern  Generation owns 75% of a 1.8 MW wind farm currently under construction
near  Kirkheaton,  Northumberland.  The project is being built by Nordex Gmbh of
Germany, and has a total cost of approximately 1.5 million pounds sterling.  The
project is scheduled for commercial operation in the second quarter of 2000.

Projects in Development
-----------------------

The following is a summary  description  of certain  information  concerning the
Company's advanced stage development projects. Since these projects are still in
development  there can be no  assurance  that this  information  will not change
materially  over time. In addition,  there can be no assurance that  development
efforts  on  any  particular  project,  or  the  Company's  development  efforts
generally,  will  be  successful.  See  also  "Risk  Factors"  contained  in the
Company's  Report  on Form 8-K  dated  March 26,  1999,  incorporated  herein by
reference.

United States

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.

Telephone  Flat.  The Company is  developing a 48 net MW  geothermal  project at
Telephone  Flat in Northern  California  where the  Company  has two  successful
production  wells (the  "Telephone  Flat  Project").  Under an amended  contract
arrangement with the Bonneville Power Administration  ("BPA"), BPA will purchase
30 MW from the project and has an option to purchase an  additional  100 MW. The
completion of the project and BPA's purchase obligation are subject to obtaining
a final environmental impact statement.

United Kingdom

The  Company,  through  Northern  Generation,  is  pursuing  a number of project
opportunities  including  several  small  embedded  combined  heat and power and
peaking  facilities,  (totaling up to 80 MW) to provide electricity to suppliers
on a local basis across Southern England. In addition,  a larger 100 MW combined
heat and  power  project  is  under  development  in  Southern  England  with an
industrial  host.  This  project  is  processing  through  the  later  stages of
government review and approval.

                                      -26-
<PAGE>

The gas moratorium in the U.K. has significantly  adversely impacted the ability
to develop gas-fired plants in the U.K.

Producing Gas Field Operations and Fields in Development
--------------------------------------------------------

CalEnergy  Gas (UK)  Limited.  CalEnergy  Gas (UK)  Limited  ("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  recently  been  involved  in  certain  gas
development and exploration activities relating to a large gas field prospect in
Poland,  the EP389  (Gingin)  concession in the Perth Basin in Australia and the
Yolla discovery in the Bass Basin of Australia.

PRODUCING GAS FIELDS   SHARE OF   CURRENT             LOCATION
                       REMAINING  % WORKING
                       RESERVES   INTEREST
                        BCF(1)

Windermere                8.7      20.000%  U.K. Offshore (North Sea)
Victor                    8.6       5.000%  U.K. Offshore (North Sea)
Schooner                  7.4       2.070%  U.K. Offshore (North Sea)
Johnston                 32.9      22.113%  U.K. Offshore (North Sea)
Anglia                   82.7      67.198%  U.K. Offshore (North Sea)

FIELDS IN DEVELOPMENT   Size Km2
Pila Area Concession    13,000(2) 100.000%  N.W. Poland (Polish Trough)
EP389 (Gingin)           2,960     40.789%  S.W. Australia Onshore (Perth Basin)
Yolla Discovery            550     20.000   S.E. Australia Offshore (Bass Basin)

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

(1) Gas reserves in Billion  cubic feet (or "Bcf") as of December 31, 1999.  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  every 2 years
during the 8 year contract term based on work program results.

Producing Fields

Windermere  Field.  The  Windermere  Field is located in the Eastern part of the
Southern North Sea approximately 62 miles east of Hull on the U.K. coast and has
remaining  reserves  of 8.7 bcf net to CE  Gas.  The  field  is  produced  by an
unmanned  platform that has two wells. The gas is transported via an 8" pipeline
to the Markham Field where it is processed, compressed and delivered through the
K13 pipeline system to the Den Helder terminal on the Netherlands  coast. CE Gas
holds a 20% working  interest in this field that  commenced  production in April
1997 and currently has average net production of 6.52 MM scfd (million  standard
cubic feet per day). Gas is sold to N.V. Nederlandse 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 on
the U.K. coast and has remaining  reserves of 8.6 bcf net to CE Gas. An unmanned
platform is installed and the field produces from 5 production wells and a sixth
subsea  well  tied  back to


                                      -27-
<PAGE>

the platform. The gas is exported through a 16" pipeline to the Viking field and
then onwards to the Theddlethorpe  shore terminal.  The Victor field has been in
production since September 1984, and currently has average  production of 4.7 MM
scfd and sells its gas to British Gas Trading Limited. CE 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  net  reserves  of 7.4 bcf.  The field is
produced  by an  unmanned  platform  which is tied back  through  an 18 mile 16"
flowline to the Murdoch  platform.  Production is achieved from seven wells. The
gas is transported through the CMS pipeline to the Theddlethorpe shore terminal.
CE Gas holds a 2.07% working  interest in the Schooner  Field,  which  commenced
production  in October 1996 and  currently  has average net  production  of 2.47
MMscfd. The CE Gas share of the gas is sold to Northern.

Johnston  Field.  The Johnston gas field is located in the Northern  part of the
Southern North Sea  approximately 56 miles north east of Scarborough on the U.K.
coast  and has  remaining  reserves  of 32.9  bcf net to CE 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 Johnston field has been in production
since October 1994. The current average net production rate is 11.7 MMscfd.  Gas
is sold to TXU Europe Upstream Limited. CE Gas has a 22.113% working interest in
this field following the outcome of an equity redefinition  process during 1999.
CE Gas previously had an 18.264% working interest in the field.

Anglia  Field.  During 1999,  CE Gas  acquired a 67.198%  interest in the Anglia
Field from  Ranger  Oil (U.K.)  Ltd.  and  Ranger  Oil (PC) Ltd.  Following  the
acquisition,  CE Gas took over the role of  operator  of the  field.  The Anglia
Field is located in the central part of the Southern North Sea, approximately 65
miles east of the  Theddlethorpe  terminal on the U.K. coast,  and has remaining
reserves of 82.7 Bcf net to CE Gas. Anglia is produced via an unmanned  platform
which has six production  wells,  and a further two subsea  production wells are
tied back to the  platform  via an 8"  pipeline.  The gas is exported  via a 12"
pipeline  to the LOGGS  platform  and then  onwards to the  Theddlethorpe  shore
terminal.  The  Anglia  Field  has been on  production  since  October  1992 and
currently has an average  production of 31.5 MM/scfd net to CE Gas. CE Gas sells
the gas to National Power and Northern.

Projects in Development

Pila Concession.  Following the execution of a Mining Usufruct Agreement in 1997
with the Polish  government,  CE Gas was awarded an eight year  exploration  and
exploitation  agreement in April 1998  providing it with the exclusive  right (a
100%  working  interest)  to explore and develop the  extensive  (13,000  square
kilometers)  undeveloped  Pila gas  concession in the Polish Trough in northwest
Poland.  CE Gas is committed to a seismic  program (now  completed) and drilling
work program within the concession over that period,  subject to  relinquishment
of up to 25% of the concession area after every two years.  Only developed areas
can be  retained  by CE Gas at the  end of the  eight  year  term.  The  Company
believes  that  there is the  potential  to  structure  an  integrated  upstream
gas/power  generation  project at the Pila  concession,  subject to (among other
things)  identifying a suitable site and negotiating an acceptable power offtake
agreement.

EP389 (Gingin)  Concession.  In August 1997, CE Gas signed an earn-in  agreement
with Empire Oil of Australia,  the permit holder for various concession areas in
the Perth Basin in Western Australia. Under the agreement, CE Gas has now earned
a  40.789%  working  interest  in the main  concession  area  and a 33%  working
interest  in four  ancillary  concession  areas.  Given  the  advantages  of the
location of the Gingin concession,  in close proximity to an industrial area and
electric   residential  load  center,  the  Company  believes  that  the  Gingin
concession   possesses  the  potential  for  an  integrated  upstream  gas/power
generation project.

Both  electricity  and gas are in the process of being opened up for competition
in Western Australia.  95% of all gas to SW Australia is currently supplied from
the NW shelf (Dampier to Bunbury pipeline--1500km).  The Perth Basin is known to
be gas  prone  but has  been  significantly  underexplored  and  underdeveloped.
Historically, gas has been a state controlled energy sector in Australia.

                                      -28-
<PAGE>

Yolla Gas  Discovery.  The Yolla gas field was discovered in 1985 and is located
offshore,  approximately  120  kilometers  from the  coast of  Tasmania  and 200
kilometers from the coast of Victoria in Australia. In 1998, CE Gas entered into
an option  agreement with Boral Energy Resources  Limited and Premier  Petroleum
(Australia) Limited to earn interests in three permits in the Bass Basin located
in the south east of Australia,  including the Yolla gas discovery. A successful
appraisal well was drilled in 1999. CE Gas' net remaining reserves are estimated
at  approximately  70 Bcf.  The  Yolla  partners  are  currently  reviewing  the
development options for the field.

U.K. Gas Transportation and Storage. The Company,  through CE Gas, is pursuing a
number of gas transportation and storage  opportunities in the U.K. to integrate
with its North Sea upstream gas production operations.

Other
-----

HomeServices

The Company owns approximately 65% of  HomeServices.Com  Inc.  ("HomeServices"),
the second largest  residential  real estate brokerage firm in the United States
based on aggregate closed  transaction  sides in 1998 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, 1998.  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.

Indonesia

On December 2, 1994,  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 the geothermal steam field and geothermal power facilities located in Central
Java in  Indonesia  with  Perusahaan  Pertambangam  Minyak  Dan Gas Cumi  Negara
("Pertamina"),  the  Indonesian  national  oil company,  and  executed  separate
"take-or-pay"  energy sales contracts with both Pertamina and P.T. PLN (Persero)
("PLN"),  the Indonesian  national electric  utility.  The Republic of Indonesia
("ROI") provided sovereign guarantees of the obligations under the "take-or-pay"
contracts.

HCE's Dieng Unit I was operationally  and contractually  completed in March 1998
when the  "take-or-pay"  obligations  under  its  contract  with PLN  commenced.
However,  PLN defaulted on the contractually  required and sovereign  guaranteed
"take-or-pay" payment obligations. The Indonesian Subsidiaries in 1998 initiated
dispute resolution  procedures under the ESCs and the sovereign  guarantees with
PLN and the Republic of Indonesia  and  subsequently  commenced  arbitration  to
resolve the dispute.  The arbitration before an international  arbitration panel
was  concluded  in 1999 and  found  that  the ROI had  materially  breached  the
contract  obligations and sovereign  guarantees and violated  international law.
The final arbitration  awards directed the ROI to pay HCE $393.4 million and PPL
$182.2 million.


                                      -29-
<PAGE>

When the ROI failed to pay the arbitration awards, the Company filed claims with
OPIC,  an agency of the U.S.  Government,  and Lloyds  private  market  insurers
pursuant to certain  insurance  that  covered  political  risks  relating to the
projects.  In 1999, the Company  received  payment of the claims filed with OPIC
and Lloyds  totaling  $290  million  and  assigned  the  Indonesia  Subsidiaries
(including the arbitration award) to OPIC.

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,  including  the
construction  or  permitting  of new and existing  facilities,  the drilling and
operation  of new and  existing  wells and the  disposal  of various  geothermal
solids.  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.

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 a power pool and
independent  system  operator and also would permit  direct access to generation
for all power purchasers outside the power exchange 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 results
of its operations.


                                      -30-
<PAGE>

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  requirement  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 Title IV CAAA requirements through 2007. 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 (i)  increasing  the lead time for the
construction of new facilities,  (ii) significantly increasing the total cost of
new  facilities,  (iii)  requiring  modification  of  certain  of the  Company's
existing facilities, (iv) increasing the risk of delay on construction projects,
(v) increasing  the Company's cost of waste disposal and (vi) 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.

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

                                      -31-
<PAGE>

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
---------

At December 31, 1999, the Company and its  subsidiaries  employed  approximately
9,700 people.  Neither the Gas Projects nor the Imperial Valley Project entities
hire or retain  any  employees.  All  employees  necessary  to  operate  the Gas
Projects and Imperial  Valley Projects are provided by affiliates of the Company
under certain administrative  services and operation and maintenance agreements.
International   development   activities  in  the  Philippines  are  principally
performed by  employees  of  affiliates  of the Company and  operations  will be
performed by employees of the local project entities.  The Company's  Philippine
affiliates currently maintain offices in Manila.

Of Northern's employees, at December 31, 1999, approximately 75% 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.

Of MidAmerican  Energy's  employees,  approximately  one half are represented by
labor unions.  MidAmerican Energy believes that its relations with its employees
are good.

As of December 31, 1999,  HomeServices employed  approximately 1,575 individuals
and had approximately  6,350 sales associates,  who are independent  contractors
and not  employees.  None of  HomeServices'  employees  or sales  associates  is
covered  by  a  collective  bargaining   agreement.   Management  believes  that
HomeServices' relations with its employees and sales associates are good.

ITEM 2. PROPERTIES

Property.  Northern  owns the  freehold of its  principal  executive  offices in
Newcastle upon Tyne, England. Northern has both network and non-network land and
buildings.  At December 31, 1999,  Northern had freehold and leasehold interests
in approximately 8,500 network properties,  comprising  principally  sub-station
sites. The recorded historical cost account net book value of total network land
and buildings at December 31, 1999 was pounds  sterling  25.9 million.  Northern
owns,  directly or indirectly,  the freehold or leasehold interests of such land
and  buildings.  At December  31, 1999,  Northern  had  freehold  and  leasehold
interests in approximately 78 non-network properties comprising chiefly offices,
retail outlets,  depots,  warehouses and workshops. The recorded historical cost
account net book value of total  non-network  land and buildings at December 31,
1999 was 17.5 million pounds sterling.

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, 1999,
included 897 miles of 345-kV lines,  1,299 miles of 161-kV lines, 1,806 miles of
69-kV lines and 219 miles of 34.5-kV lines. The gas  distribution  facilities of
MidAmerican Energy at December 31, 1999,  included 19,907 miles of gas mains and
services.  Substantially  all 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.

                                      -32-
<PAGE>

The Company  also  maintains  an inventory  of  approximately  150,000  acres of
geothermal  property leases.  Certain of the producing acreage owned by Magma is
leased to unaffiliated  power plants,  and Magma, as lessor,  receives royalties
from the revenues  earned by such power  plants.  The Company,  as lessee,  pays
certain  royalties  and other  fees to the  property  owners  and other  royalty
interest holders from the revenue generated by the Imperial Valley Project.  The
Company leases its principal executive offices and its offices in Manila.

Lessors  and  royalty  holders  are  generally  paid a monthly or annual  rental
payment  during the term of the lease or mineral  interest  unless and until the
acreage goes into  production,  in which case the rental typically stops and the
(generally  higher)  royalty  payments  begin.  Leases of federal  property  are
transacted with the Department of Interior, Bureau of Land Management,  pursuant
to standard geothermal leases under the Geothermal Steam Act and the regulations
promulgated  thereunder  (the  "Regulations"),  and are for a primary term of 10
years,  extendible for an additional five years if drilling is commenced  within
the primary term and is diligently pursued for two successive  five-year periods
upon certain conditions set forth in the Regulations.  A secondary term of up to
40 years is  available  so long as  geothermal  resources  from the property are
being produced or used in commercial quantities.  Leases of state lands may vary
in form.  Leases of  private  lands vary  considerably,  since  their  terms and
provisions are the product of negotiations with the landowners.

HomeServices'  principal  offices  are  located  in  Edina,   Minnesota,   where
HomeServices leases approximately 46,000 square feet of office space. This lease
expires in 2003. The rent under this lease is  approximately  $600,000 per year.
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.

ITEM 3. LEGAL PROCEEDINGS

The Company is not a party to any material pending legal  proceedings.  However,
as described herein,  certain of the Company's projects and utility subsidiaries
are parties to litigation or other disputes.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Not applicable.



                                      -33-
<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.
                                      -34-
<PAGE>


                                    PART III

                                   MANAGEMENT

ITEM 10.  DIRECTORS, EXECUTIVE AND OTHER OFFICERS OF THE COMPANY AND SIGNIFICAN
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                          Company

David L. Sokol             Chairman of the Board and Chief
                             Executive Officer               MEHC, MEC, Northern
Gregory E. Abel            President and Chief Operating
                              Officer                        MEHC, Northern
Patrick J. Goodman         Senior Vice President and Chief
                              Financial Officer              MEHC, MEC
Steven A. McArthur         Senior Vice President, Mergers and
                              Acquisitions and Secretary     MEHC, MEC
John A. Rasmussen Jr.      Senior Vice President and
                              General Counsel                MEHC, MEC
Keith D. Hartje            Senior Vice President and Chief
                              Administrative Officer         MEHC, MEC
Robert S. Silberman        Senior Vice President and President,
                              CalEnergy Generation           MEHC
Douglas L. Anderson        Vice President, Assistant General
                              Counsel and General Counsel,
                              CalEnergy Generation           MEHC
Edward F. Bazemore         Vice President, Human
                              Resources/IPP                  MEHC, MEC
James A. Flores            Vice President, Project
                              Finance                        MEHC
Adrian M. Foley III        Vice President, Marketing         MEHC
Brian K. Hankel            Vice President and Treasurer      MEHC, MEC
Paul J. Leighton           Vice President Corporate Law,
                              Assistant General Counsel
                              and Assistant Secretary        MEHC, MEC
Joseph M. Lillo            Vice President and Controller     MEHC
James J. Sellner           Director of Taxation, Corporate   MEHC, MEC
K. Taylor Smith            Controller, Asian Operations      MEHC
Jonathan M. Weisgall       Vice President, Federal
                              Regulation                     MEHC, MEC
Russell H. White           Assistant Vice President,
                              General Services               MEHC, MEC
Cathy S. Woollums          Vice President, Environmental     MEHC, MEC
Ronald W. Stepien          President                         MEC
Jack L. Alexander          Senior Vice President, Transmission
                              and Energy Delivery            MEC
David C. Caris             Vice President, State
                              Government Affairs             MEC
Dean A. Crist              Vice President, Generation        MEC
Steven J. Dust             Vice President, Economic
                              Development                    MEC
Brent E. Gale              Vice President, Legislation
                              and Regulation                 MEC
David L. Graham            Vice President, Customer Service  MEC
James J. Howard            Vice President, Regulatory
                              Affairs                        MEC
Todd M. Raba               Vice President, Retail Business
                              Unit                           MEC
Mark W. Roberts            Vice President, Energy Trading
                              and Planning                   MEC
Thomas B. Specketer        Vice President & Controller       MEC
Steven R.  Weiss           Assistant General Counsel         MEC
P. Eric Connor             President and Chief Operating
                              Officer                        Northern
Dave Crompton              Managing Director, Retail         Northern
Dr. John M. France         Director of Regulation            Northern
G. Valerie Giles           Company Secretary                 Northern
Mark Horsley               Managing Director, Northern
                              Utility Services Limited       Northern
Dr. Philip S. Lawless      Managing Director, Generation     Northern
Ken Linge                  Director of Finance               Northern

                                      -35-
<PAGE>

Neil Middleton             Managing Director, Northern
                              Electric Supply Limited        Northern
James D. Stallmeyer        Vice President, Commercial
                              Director and General Counsel   Northern
David Swan                 Distribution Director             Northern
David A. Waters            Managing Director, Northern
                              Electric Distribution Limited  Northern
Peter Youngs               Managing Director, CalEnergy
                              Gas (UK) Ltd.                  Northern

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

DAVID L. SOKOL,  43,  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, 37, 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  1984 to 1992 he was  employed  by  Price
Waterhouse. As a Manager in the San Francisco office of Price Waterhouse, he was
responsible for clients in the energy industry.

PATRICK J. GOODMAN,  33, Senior Vice President and Chief Financial Officer.  Mr.
Goodman joined the Company in 1995, 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,  42, Senior Vice  President,  Mergers and  Acquisitions  and
Secretary.  Mr.  McArthur  joined the Company in February 1991 and has served in
various executive capacities including General Counsel. 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.

JOHN A.  RASMUSSEN,  JR., 54,  Senior Vice  President and General  Counsel.  Mr.
Rasmussen  has been Senior Vice  President  and General  Counsel of  MidAmerican
Energy since November 1, 1996, and Group Vice President and General Counsel from
July 1,  1995 to  November  1,  1996.  Prior to that he was Vice  President  and
General Counsel of Midwest Power Systems, Inc., a predecessor company, from 1993
to 1995.

KEITH D. HARTJE, 50, 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.

ROBERT S. SILBERMAN, 42, Senior Vice President. Mr. Silberman joined the Company
in 1995.  Prior to that,  Mr.  Silberman  served as  Executive  Assistant to the
Chairman and Chief Executive Officer of International Paper Company, as Director
of Project Finance and Implementation for the Ogden Corporation and as a Project
Manager in Business  Development for  Allied-Signal,  Inc. He has also served as
the Assistant Secretary of the Army for the United States Department of Defense.

DOUGLAS L.  ANDERSON,  42, Vice  President and Assistant  General  Counsel.  Mr.
Anderson  joined the Company in February 1993.  From 1990 to 1993, Mr.  Anderson
was a business attorney with Fraser,  Stryker,  Vaughn,  Meusey,  Olson, Boyer &
Bloch,  P.C. in Omaha.  Prior to that, Mr.  Anderson was a principal in the firm
Anderson & Anderson.

                                      -36-
<PAGE>

EDWARD F. BAZEMORE, 63, Vice President, Human Resources/IPP. Mr. Bazemore joined
the  Company  in July  1991.  From 1989 to 1991,  he was Vice  President,  Human
Resources,  at Ogden Projects,  Inc. in New Jersey.  Prior to that, Mr. Bazemore
was  Director  of Human  Resources  for Ricoh  Corporation,  also in New Jersey.
Previously,  he was  Director  of  Industrial  Relations  for  Scripto,  Inc. in
Atlanta, Georgia.

JAMES A. FLORES,  46, Vice  President,  Project  Finance.  Mr. Flores joined the
Company in May 1994.  Mr.  Flores was  employed  for 12 years with Mellon  Bank,
first in its Latin American Group and subsequently in its Project Finance Group.

ADRIAN M. FOLEY,  III,  53, Vice  President,  Marketing.  Mr.  Foley  joined the
Company in January  1994 as Project  Development  Manager and  continued in that
capacity until January 1997 when he was promoted to Vice  President,  Marketing.
Prior  to  joining  the  Company,  Mr.  Foley  was  Regional  Manager,  Business
Development  with Ogden  Projects,  Inc.  from 1989 to 1993 and  Executive  Vice
President with Rescom Development Company from 1980 to 1989.

BRIAN K. HANKEL, 37, Vice President and Treasurer. Mr. Hankel joined the Company
in  February  1992 as Treasury  Analyst and served in that  position to December
1995.  Mr. Hankel was  appointed to Assistant  Treasurer in January 1996 and was
appointed  Treasurer in January 1997.  Prior to joining the Company,  Mr. Hankel
was a Money  Position  Analyst at FirsTier Bank of Lincoln from 1988 to 1992 and
Senior Credit Analyst at FirsTier from 1987 to 1988.

PAUL J. LEIGHTON,  46, Vice President,  Corporate Law, Assistant General Counsel
and  Assistant  Secretary.  Mr.  Leighton has served as Corporate  Secretary for
MidAmerican  Energy and its predecessor  companies since 1988 and as an attorney
since 1978.

JOSEPH M. LILLO, 30, Vice President and Controller. Mr. Lillo joined the Company
in November 1996, and served as Manager of Financial  Reporting and was promoted
to  Controller/IPP  in March 1998.  Mr. Lillo was promoted to Controller in July
1999.  Prior to joining  the  Company,  Mr.  Lillo was a senior  associate  with
Coopers & Lybrand LLP.

JAMES J. SELLNER,  53,  Director of Taxation.  Mr. Sellner joined the Company in
November,  1997.  Prior to joining the  Company,  Mr.  Sellner  was  employed by
Central and South West Corporation and Banc One/MCorp.

K. TAYLOR SMITH, 43, Controller,  Asian Operations. Mr. Smith joined the Company
in 1991.  From  1986 to 1991 Mr.  Smith  was  employed  by  Computer  Technology
Associates,  Inc. with  responsibilities  including  computer systems design and
development, financial planning and management.

JONATHAN M. WEISGALL, 51, Vice President,  Federal Regulation/IPP.  Mr. Weisgall
joined the Company in May 1995.  Prior to that, Mr.  Weisgall was an attorney in
private  practice  with  extensive  energy  and  regulatory  experience  and  is
currently Adjunct Professor of Energy Law at Georgetown University Law Center.

RUSSELL H. WHITE, 53, Assistant Vice President,  General Services. Mr. White was
previously  Manager,  General Services.  Mr. White joined the Company in 1988 as
Manager, Asset Protection.

CATHY WOOLLUMS, 39, Vice President,  Environmental. Ms. Woollums was an Attorney
for Iowa-Illinois Gas and Electric Company from 1991-1995.  From 1995-1998,  she
was Manager, Environmental Services with MidAmerican Energy.

RONALD W. STEPIEN,  53, President of MidAmerican  Energy since November 1, 1998,
Executive  Vice  President  from November 1, 1996 to October 31, 1998, and Group
Vice  President from 1995 to November 1, 1996.  Vice President of  Iowa-Illinois
Gas and Electric Company, a predecessor company, from 1990 to 1995.

                                      -37-
<PAGE>

JACK L.  ALEXANDER,  52,  Senior  Vice  President  of  MidAmerican  Energy.  Mr.
Alexander has been Senior Vice President of MidAmerican Energy since November 1,
1998 and was a Vice  President of  MidAmerican  Energy from  November 1, 1996 to
October 31, 1998,  and held various  executive  and  management  positions  with
MidAmerican and Midwest Power Systems Inc., a predecessor company, for more than
five years prior thereto.

DAVE CARIS, 40, Vice President,  State Government Affairs of MidAmerican Energy.
Mr. Caris was  Government  Affairs Vice  President for  MidAmerican  Energy from
November  1,  1997 to March 19,  1999 and  Manager  of  Government  Affairs  for
Iowa-Illinois Gas & Electric Company, a predecessor company, from 1986-1995.

DEAN A. CRIST, 44, Vice President,  Generation of MidAmerican  Energy. Mr. Crist
has  been in his  present  position  since  April  9,  1999  and was  Generation
Marketing Vice  President of  MidAmerican  Energy from April 1, 1998 to April 9,
1999 and held  various  management  positions  with  MidAmerican  Energy and its
predecessor companies for more than five years prior thereto.

STEVEN J. DUST, 45, Vice President,  Economic Development of MidAmerican Energy.
Mr. Dust has been in his present  position  since  February,  1999. Mr. Dust has
over twenty  year's  experience  in the  economic  development  field and joined
MidAmerican Energy as Manager of Economic  Development in 1996. Prior to joining
MidAmerican,  Steve was a Principal of Septagon Industries,  a Midwest firm with
holdings in industrial construction, real estate development, manufacturing, and
communications.

BRENT E. GALE,  48, Vice  President,  Legislation  and Regulation of MidAmerican
Energy.  Mr. Gale has previously held positions with MidAmerican  Energy as Vice
President - Regulatory  Law and Analysis and Vice  President - Law & Regulation.
Prior to 1995,  Mr. Gale was Vice President - General  Counsel of  Iowa-Illinois
Gas and Electric Company, a predecessor company.

DAVID L. GRAHAM, 54, Vice President,  Customer Service,  of MidAmerican  Energy.
Mr. Graham has been in his present  position  since  December 1998 and was Sales
Vice President  from April 1998 to December  1998,  and held various  management
positions with MidAmerican Energy and its predecessor companies for more than 30
years prior thereto.

JAMES J. HOWARD, 57, Vice President,  Regulatory Affairs of MidAmerican  Energy.
Mr.  Howard has been Vice  President,  Regulatory  Affairs  since  April,  1998.
Previously he had been Vice President, Administrative Services since 1989.

TODD M. RABA, 43, Vice President,  Marketing and Sales. Mr. Raba has been in his
present  position  since April 1999. He joined  MidAmerican  in December 1997 as
Sales  Vice  President,   responsible  for  Major  Accounts.  Prior  to  joining
MidAmerican, Mr. Raba spent 13 years at Rollins Environmental Services, Inc., of
Wilmington Delaware. His most recent assignments there included Northeast Region
Vice President and National Director of Sales.

MARK W. ROBERTS, 43, Vice President,  Energy Trading and Planning of MidAmerican
Energy.  Mr. Roberts has been in his present position since April 1999 and was a
manager and then vice  president of  MidAmerican  Energy's  generation  business
services from December 1996 to April 1999.  Prior to that time, Mr. Roberts held
various  management  positions  with  MidAmerican  Energy  and  its  predecessor
companies for more than five years.

THOMAS B.  SPECKETER,  43, Vice President and  Controller of MidAmerican  Energy
Company. Mr. Specketer has been in his present position since September 1999 and
has over twenty years of accounting and tax experience with  MidAmerican  Energy
and its predecessor companies.

STEVEN R. WEISS, 45, Assistant General Counsel of MidAmerican  Energy. Mr. Weiss
has been with  MidAmerican  Energy  and its  predecessor  companies  since  1987
providing  support to both the regulated and competitive  sides of the business.
He was  appointed  to his  current  position  in March  1999.  Prior to  joining


                                      -38-
<PAGE>

MidAmerican  Energy he served as a Hearing  Examiner for the  Illinois  Commerce
Commission from 1982 until 1987.

P.  ERIC  CONNOR,  51,  Director,  Northern  Electric  and  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.

DAVE CROMPTON,  46, Managing  Director,  Northern Electric Retail.  Mr. Crompton
joined Northern Electric Retail in April 1990 where he served as Sales Director,
and earlier this year also took over the Marketing function.  He became Managing
Director in June 1997.  During his time with  Northern  Electric he has gained a
Master in Business  Administration  at Durham  University.  Mr.  Crompton has 26
years   experience  in  electrical   retailing  of  which  19  years  were  with
Dixons/Currys  where he held the posts of Regional  Sales Manager and Divisional
Marketing Manager.

DR. JOHN M. FRANCE, 42, Director,  Northern Electric and Director of Regulation,
Northern  Electric.  Mr. France joined  Northern in 1989 as Regulation  Manager.
Between 1982 to 1989,  Mr.  France held a number of  regulatory  positions  with
British Gas.

G. VALERIE GILES, 48, Company  Secretary,  Northern  Electric.  Ms. Giles joined
Northern Electric in 1989. From 1987 to 1989 she was Assistant Company Secretary
at Amersham  International plc and worked in their legal department from 1974 to
1987.

NEIL MIDDLETON,  35, Managing  Director,  Northern Electric Supply Limited.  Mr.
Middleton  joined  Nothern in 1989 having  studied  Electrical  and  Electronics
Engineering  at the  University of Newcastle  Upon Tyne.  Prior to taking up his
current  appointment,  Mr.  Middleton  worked  in  the  Pricing  and  Purchasing
Departments.

DR. PHILIP S. LAWLESS, 38, Managing Director, Generation, Northern Electric. Mr.
Lawless  joined  Northern  in  1989  as  Contract   Development  Officer  (Power
Purchase).  His previous positions in Northern include Project  Manager-Teesside
Power Limited and Generation  Projects Manager.  Prior to joining  Northern,  he
worked at NEI Parsons Ltd, where he held various positions,  and North Kalgurlie
Mines Ltd, Australia, as an Assistant Plant Metallurgist.

KEN LINGE, 50, Director of Finance, Northern Electric. Mr. Linge joined Northern
as an  accountancy  trainee in 1968.  He has held a variety  of  finance  posts.
Current  responsibilities  include  financial  planning,   taxation,   treasury,
pensions, and group accounting services.

MARK HORSLEY,  40, Managing  Director,  Northern Utility Services  Limited.  Mr.
Horsley joined Northern in 1975 as a craft  apprentice and  subsequently  held a
number of progressing senior engineering positions.

JAMES D.  STALLMEYER,  42,  Director,  Northern  Electric and Vice President and
Commercial  Director and General  Counsel,  Northern  Electric.  Mr.  Stallmeyer
joined the Company in 1993. Mr.  Stallmeyer  practiced in the public finance and
banking  areas at Chapman  and  Cutler in  Chicago  from 1984 to 1987 and in the
corporate  finance  department from 1989 to 1993. Prior to that, Mr.  Stallmeyer
was an  attorney  in the public  finance  department  of the  Chicago  office of
Skadden,  Arps,  Slate,  Meagher & Flom in 1987 and 1988 and was a legal writing
instructor at the University of Illinois College of Law in 1988 and 1989.

DAVID SWAN, 55, Distribution  Director. Mr. Swan joined Northern in 1966 and has
held posts in varying disciplines  including  distribution,  engineering design,
operations,   customers   engineering,   customer   relationships,   engineering
contracting, logistics, computer systems development and project management.

                                      -39-
<PAGE>

DAVID A. WATERS, 57, Managing Director,  Northern Electric Distribution Limited.
Mr. Waters joined Northern in September 1960 as a Student Apprentice. In 1982 he
became a Resources  Engineer and received  appointments as Cleveland  (Teesside)
Technical  Distribution System Planning Manager,  Business  Development Manager,
later  promoted to Business  Services  Manager and General  Manager,  NUSL.  The
following March 1998 he was appointed as Managing Director.

PETER YOUNGS, 45, Managing Director, Gas Exploration and Development. Mr. Youngs
joined  Neste Oy in 1974 as a  Geoscientist  and held  the  following  positions
within  the  company:   International   Exploration  Manager,   General  Manager
(Europe-Africa  Region), Vice President and Managing Director UKEXPRO. From 1994
to present, he has been the General Manager of CalEnergy Gas (UK) Limited.

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.




                                      -40-
<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...............................42
          Management's Discussion and Analysis of Financial Condition
            And Results of Operations........................................43
          Qualitative and Quantitative Disclosures About Market Risk.........56
          Consolidated Balance Sheets as of December 31, 1999 and 1998.......59
          Consolidated Statements of Operations
            For the Three Years Ended December 31, 1999, 1998 and 1997.......60
          Consolidated Statements of Stockholders' Equity
            For the Three Years Ended December 31, 1999, 1998 and 1997.......61
          Consolidated Statements of Cash Flows
            For the Three Years Ended December 31, 1999, 1998 and 1997.......62
          Notes to Consolidated Financial Statements.........................63
          Report of Independent Accountants..................................96

     2.   Financial Statement Schedules Page No.

          Schedule I, Financial Statements of the Company
            (Parent Company only)............................................97

     (b)  Reports on Form 8-K

          The Company  filed a Current  Report on Form 8-K dated October 8, 1999
          announcing  received  tenders and consent from holders of an aggregate
          of $119 million principal amount of its 9 1/2% Senior Notes due 2006.

          The Company filed a Current  Report on Form 8-K dated October 20, 1999
          announcing  that  the   International   Arbitration   Panel  announces
          favorable  final decisions for Himpurna  California  Energy and Patuha
          Power requiring Republic of Indonesia to pay $575,000,000.

          The Company filed a Current  Report on Form 8-K dated October 21, 1999
          announcing  that on October 20,  1999,  it has  established  the final
          pricing  for the  tender  of its 9 1/2%  Senior  Notes  due  2006,  in
          connection with its previously announced cash tender offer and consent
          solicitation for such Notes.

          The Company filed a Current  Report on Form 8-K dated October 24, 1999
          announcing  that it had entered into an Agreement  and Plan of Merger,
          dated as of October 24, 1999 with entities formed by an investor group
          including  Berkshire  Hathaway  Inc.,  Walter Scott,  Jr. and David L.
          Sokol.

     (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.


                                      -41-
<PAGE>

                      SELECTED CONSOLIDATED FINANCIAL DATA
                    (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>

                                                                     YEAR ENDED DECEMBER 31
                                          -------------------------------------------------------------------------
                                            1999 (1)        1998(2)        1997              1996(3)      1995(4)
                                          -----------     ----------     ----------        ----------   -----------
<S>                                       <C>             <C>            <C>               <C>          <C>
INCOME STATEMENT DATA:
Operating revenue                         $ 4,128,737     $2,555,206     $2,166,338        $  518,934   $  335,630
Total revenue                               4,398,783      2,682,711      2,270,911           576,195      398,723
Total costs and expenses                    4,041,714      2,410,658      2,074,051           435,791      301,672
Income before provision for
  income taxes                                357,069        272,053        196,860(6)        140,404       97,051
Minority interest                              46,923         41,276         45,993             6,122        3,005
Income before change in accounting
  principle and extraordinary item            216,671(5)     137,512         51,823(6)         92,461       63,415
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)                             167,230(5)     127,003        (84,027)(6)        92,461       63,415
Income per share before change in
  accounting principle and
  extraordinary item                      $      3.62(5)  $     2.29     $     0.77(6)     $     1.69   $     1.32
Extraordinary item per share                     (.83)          (.12)         (2.02)               --           --
Cumulative effect of change in
  accounting principle per share                   --           (.06)            --                --           --
Net income (loss) per share               $      2.79(5)  $     2.11     $    (1.25)(6)    $     1.69   $     1.32
Basic common shares outstanding                59,929         60,139         67,268            54,739       47,249
Income per share before extraordinary
  item and cumulative effect of change
  in accounting - diluted                 $      3.28(5)  $     2.15     $     0.75(6)     $     1.54   $     1.22
Extraordinary item - diluted                     (.69)          (.10)         (1.97)               --           --
Cumulative effect of change in
  accounting principle - diluted                   --           (.04)            --                --           --
Net income (loss) per share - diluted     $      2.59(5)  $     2.01     $    (1.22)(6)    $     1.54   $     1.22
Diluted shares outstanding                     71,948         74,100         68,686            65,072       56,195

BALANCE SHEET DATA:
Total assets                              $10,766,352     $9,103,524     $7,487,626        $5,630,156   $2,654,038
Total liabilities                           8,978,924      7,598,040      5,282,162         4,181,052    2,084,474
Company-obligated mandatorily
  redeemable convertible preferred
  securities of subsidiary trusts             450,000        553,930        553,930           103,930           --
Subsidiary-obligated mandatorily
  redeemable preferred securities
  of subsidiary trusts                        101,598             --             --                --           --
Preferred securities of subsidiaries          146,606         66,033         56,181           136,065           --
Total stockholders' equity                    994,588        827,053        765,326           880,790      543,532

</TABLE>

     (1)  Reflects the MidAmerican Merger owned for a portion of the year,
          the disposition of Coso Joint ventures during the year, and the
          disposition of 50% ownership interest in CE Generation
     (2)  Reflects the acquisition of KDG.
     (3)  Reflects the acquisitions of Northern, Falcon Seaboard and the
          Partnership Interest owned for a portion of the year.
     (4)  Reflects the acquisition of Magma Power Company owned for a portion of
          the year.
     (5)  Includes $81,556, $1.36 per basic share and $1.13 per diluted share
          for non-recurring Indonesia gain on settlement, gains on sales of
          McLeod and qualified facilities, Northern restructuring charges and
          Berkshire transaction costs.
     (6)  Includes the $87,000, $1.29 per basic share, $1.27 per diluted share,
          non-recurring Indonesian asset impairment charge.

                                      -42-

<PAGE>

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

Business of MEHC

MidAmerican  Energy  Holdings  Company (the  "Company"  or "MEHC"),  is a United
States-based  privately  owned global energy company with publicly  traded fixed
income securities that generates,  distributes and supplies energy to utilities,
government entities, retail customers and other customers located throughout the
world.  Through its  subsidiaries  the Company is organized and managed on three
separate platforms:

MidAmerican

MidAmerican  Energy ("MEC") 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. MEC 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, 1999,
MEC had  663,500  retail  electric  customers  and  638,000  retail  natural gas
customers.

In addition to retail sales,  MEC 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.

MEC'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.

MEC has a  residential,  agricultural,  commercial  and  diversified  industrial
customer group, in which no single industry or customer  accounted for more than
5% of its total 1999  electric  operating  revenues  or 3% of its total 1999 gas
operating margin.  Among the primary industries served by MEC are those that 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.

Most  of  MEC'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. MEC'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.

MidAmerican Capital Company manages marketable securities and passive investment
activities, security services and other energy-related, nonregulated activities.
MidAmerican  Services Company provides energy  management and related  services.
Midwest Capital Group, Inc. functions as a regional business development company
in MEC's service territory.

Through October 6, 1999, MHC Inc. owned approximately 95% of the common stock of
MidAmerican Realty Services. On October 6, 1999, MidAmerican Realty Services was
dividended  out of MHC Inc.  to the  Company  and merged  with  HomeServices.Com
("HomeServices"),  a  subsidiary  of  the  Company.  HomeServices  includes  the
Company's real estate  brokerage  operations and offers  integrated  real estate
services in eleven states including residential  brokerage,  relocation,  title,
abstract and mortgage  services.  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%.

                                      -43-
<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.

On December 2, 1999, the United Kingdom's Office of Gas and Electricity  Markets
("Ofgem")  issued its final  proposals for regulated  revenue  reduction for the
distribution business of Northern to be effective from April 1, 2000. The report
proposed revenue reductions for all public electricity supply companies in Great
Britain  including a reduction of 24% (equivalent to  approximately  $76 million
for a full year) for Northern.  The proposals have been accepted by the Company.
To mitigate the effects of the revenue reduction,  Northern is in the process of
implementing  a series of cost  reduction  initiatives  including  a  redundancy
program which will result in 500 employees leaving Northern.

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 which tends to operate at
lower profitability levels than the distribution business.  Prior to November 4,
1998,  Northern was the  exclusive  supplier of  electricity  to premises in its
authorized area,  except where the maximum demand of a customer was greater than
100kW.  Beginning  November  4, 1998,  liberalization  of the  entire  market in
Northern's  area  commenced in stages with complete  liberalization  achieved in
Northern's authorized area by the end of April 1999. In the market between 100kW
and 1MW of  electrical  demand,  Northern  is now one  the  largest  electricity
suppliers  in the U.K.  market.  As of  December  31,  1999,  Northern  supplied
electricity to 1,339,000 customers.

Also,  on December 2, 1999,  Ofgem issued its final  proposals  for  electricity
supply prices for the two years ended March 31, 2002.  The proposals  which have
been accepted by the Company  relate mainly to domestic  customers in Northern's
authorized area and will lead to a price reduction of approximately  11% in real
terms with effect from April 1, 2000.

Northern also competes to supply gas inside and outside its authorized  area. In
the residential market Northern currently supplies gas to approximately  570,000
customers and is now the fourth  largest gas supplier of the new entrants in the
U.K. residential market.

CalEnergy

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),  Elmore and
Leathers (collectively the "Partnership Projects") are based on capacity amounts
of 34, 38, 38, and 38 net MW, respectively, and for Salton Sea I, Salton Sea II,
Salton Sea III and Salton Sea IV plants (collectively the "Salton Sea Projects")
are based on capacity amounts of 10, 20, 49.8 and 39.6 net MW, respectively (the
Partnership Projects and the Salton Sea Projects are collectively referred to as
the "Imperial  Valley  Projects").  Plant  capacity  factors for Saranac,  Power
Resources, NorCon and Yuma (collectively the "Gas Plants") are based on capacity
amounts of 240, 200, 80, and 50


                                      -44-
<PAGE>

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.

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  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 ("Caithness").  The price included $205 million in cash
and $5 million in contingent payments.

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 Berkshire  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.

Berkshire 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  Berkshire
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 nontransferable  trust preferred stock. 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 not more than 9.9% 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 Company incurred  approximately $6.7 million of non-recurring costs in 1999,
related to the Berkshire transaction, which were expensed.

Acquisitions/Dispositions

MidAmerican Merger

On August 11, 1998,  the Company  entered  into an Agreement  and Plan of Merger
with 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



                                      -45-
<PAGE>

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.

Qualified Facilities Disposition

The  consummation  of the MidAmerican  Merger was conditioned  upon receipt of a
number of regulatory and  shareholder  approvals and the  disposition of partial
interests in certain of the Company's  power  generating  facilities in order to
maintain the qualifying  facilities  status of such independent 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  ownership
interests in the Coso Joint Ventures to 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 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. On
March 3, 1999, the Company closed the sale of 50% of its ownership  interests in
CE  Generation  to an affiliate of El Paso Energy  Corporation  for an aggregate
consideration of approximately  $245 million in cash, $6.5 million in contingent
payments and $23.5 million in equity commitments.

The sales of the qualified  facilities  resulted in a net non-recurring  pre-tax
gain of $20.2 million and an after-tax  gain of  approximately  $12.4 million or
$0.17 per diluted share.

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
or $0.65 per diluted share.

HomeServices

On October 18, 1999, the Company  announced that  HomeServices,  a subsidiary of
the Company,  closed its initial public  offering of 3,250,000  shares of common
stock at $15 per share.  HomeServices sold 2,187,500 shares and the Company, the
selling stockholder, sold 1,062,500 shares in the offering.  HomeServices is the
surviving entity of a merger with MidAmerican Realty Services.

Indonesia

On December 2, 1994,  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  Pertambangan  Minyak  Dan Gas Bumi  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.


                                      -46-
<PAGE>

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,
assuming proceeds from political risk insurance and no tax benefits.

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 ("MOF") 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,  which 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.

The Company  carried  political  risk insurance on its investment in HCE and PPL
through  OPIC,  an agency of the U.S.  Government,  as well as  through  private
market  insurers.   Such  insurance  covered   expropriation  of  the  Company's
investment  in HCE and PPL, as well as material  breaches by PLN of the ESCs and
by the ROI of its  performance  undertakings.  On November 18, 1999, the Company
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 the  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, or $0.81 per diluted share.

Results of Operations For The Years Ended December 31, 1999, 1998 and 1997

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.

Operating  revenues increased to $2,555.2 million in the year ended December 31,
1998,  from  $2,166.3  million in the year ended  December  31,  1997,  an 18.0%
increase.  This growth was primarily due to higher volumes and related  revenues
of gas and  electricity  supplied by Northern,  commencement  of  operations  at
Malitbog Units II and III in the third quarter of 1997, and the consolidation of
the  Mahanagdong  project  resulting  from the KDG  Acquisition  which  had been
accounted for using the equity method of accounting.

                                      -47-
<PAGE>

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

                                                   Year Ended December 31,
                                               -----------------------------
                                                1999       1998        1997
                                                ----       ----        ----

Electricity Supplied (GWh)..............       17,984     15,313      14,378

Electricity Distributed (GWh)...........       15,943     15,904      15,714

Gas Supplied (Therms in millions) ......        484.2      359.5        74.5

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.

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

                                                     Year Ended December 31,
                                                  -----------------------------
                                                   1999        1998       1997
                                                   ----        ----       ----

Electric Retail Sales (GWh).............          16,007      16,088     15,666

Electric Sales for Resale (GWh).........           7,168       6,186      6,987

Gas Throughput (Therms in millions).....             812         820        938

Interest and other income  increased for the year ended  December 1999 to $131.3
million  from  $127.5  million in the same period in 1998.  The  addition of MHC
amounts following the MidAmerican  Merger and the addition of equity income from
CE  Generation  accounted  for the  increase  partially  offset by  reduction of
operator  fees  related  to the  qualified  facilities  that  we  sold in 1999 .
Interest  and other  income  increased  in 1998 to $127.5  million  from  $104.6
million in 1997, a 21.9%  increase.  This increase was due primarily to interest
earned by Casecnan  on the cash held for  construction,  interest  earned on the
proceeds of the senior note and bond  offering and the  dividends  received from
our  investment  in Teesside  Power  Limited,  partially  offset by lower equity
earnings due to the consolidation of Mahanagdong equity interest in 1998.

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 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 higher volumes of gas and electricity  supplied at Northern and
the  MidAmerican  Merger.  The  acquisition  of MHC added $655.2  million in the
period March 12, 1999 through  December  31,  1999.  Cost of sales  increased to
$1,258.5  million  in 1998 from  $1,055.2  million  in 1997.  This  increase  is
primarily due to higher volumes of gas and electricity supplied.

Operating  expense  increased in the year to date ended  December 1999 to $989.6
million from $471.4 million for the same period in 1998, a 109.9% increase.  The
MidAmerican  Merger  added  $597.3  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.



                                      -48-
<PAGE>

Operating  expense  increased to $471.4  million in 1998 from $398.5  million in
1997,  an increase of 18.3%.  This  increase is due to an increase in Northern's
customer  acquisition  costs,  including  commissions  and  opening  meter reads
associated with the opening of the competitive gas supply market.

Depreciation  and  amortization  increased in the year to date  December 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.  Depreciation  and  amortization  increased to $333.4
million in 1998 from $276.0 million in 1997, an increase of 20.8%. This increase
is due to the  commencement of operations at Mahanagdong and Units II and III at
Malitbog  and the  amortization  of the  allocated  purchase  price and goodwill
related to the acquisition of KDG.

As a result of the acquisition of KDG,  Casecnan is fully  consolidated into the
Company's  financial  statements  beginning  January  2,  1998 and is no  longer
recorded as an equity investment.

Interest  expense,  less  amounts  capitalized,  increased  in the  year to date
December  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. Interest expense, less amounts capitalized, increased
in 1998 to $347.3  million from $251.3  million in 1997, a 38.2%  increase.  The
increase is primarily due to the  consolidation  of Casecnan  resulting from the
KDG  Acquisition,   the  greater  average  outstanding  debt,  the  discontinued
capitalization  of interest due to the commencement of operations at Mahanagdong
and Units II and III at Malitbog and the discontinued capitalization of interest
in Indonesia as a result of the suspension of construction activity.

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  Berkshire
transaction.

The  non-recurring  charge of $87 million in 1997 represented an asset valuation
impairment   under  Statement  of  Financial   Accounting   Standards  No.  121,
"Accounting for the Impairment of Long-Lived  Assets," relating to the Company's
assets in Indonesia.  The charge  included all  reasonably  estimated cash flows
associated  with the  Company's  assets  in  Indonesia  and gave  effect  to the
political risk insurance on such investments.

The  provision  for income taxes  increased  marginally to $93.5 million in 1999
from  $93.3  million in 1998 and  decreased  from  $99.0  million  in 1997.  The
decrease  from 1997 to 1998 is due to lower  pre-tax  book income that  resulted
from  increased  dividends on  convertible  preferred  securities  of subsidiary
trusts.  After  adjusting  for  the  non-recurring  gains  and  losses  and  the
deductible dividends on preferred securities,  the effective tax rate was 38.7%,
39.5% and 38.0% in 1999, 1998 and 1997 respectively.

Minority interest consists of dividends on preferred  securities of subsidiaries
and minority ownership of HomeServices.  Minority interest increased in the year
ended  December  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. Minority
interest  decreased  to $41.3  million  in 1998 from $46.0  million  in 1997,  a
decrease of 10.3%.  This  decrease is a result of the  purchase of Northern  and
KDG's minority interest,  partially offset by increased dividends on convertible
preferred securities of subsidiary trusts.

Income before  extraordinary  items increased in the year ended December 1999 to
$216.7  million  or $3.62 per share  from  $137.5  million or $2.29 per share in
1998, and $51.8 million or $0.77 per share in 1997. Excluding the $87.0 million,
$1.29 per share,  non-recurring  charge,  income before extraordinary item would
have been $138.8 million or $2.06 per share in 1997.

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.

                                      -49-
<PAGE>

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."

On July 31, 1997, the Finance Act in the United Kingdom was passed by Parliament
and included the  introduction  of a one time so-called  "windfall tax" equal to
23% of the difference between the price paid for Northern upon privatization and
the Labour government's  assessed "value" of Northern as calculated by reference
to a formula set forth in the July 1997 budget. This amounted to $135.9 million,
net of minority  interest,  which was recorded as an extraordinary item in 1997.
The first installment was paid on December 1, 1997 and the remainder was paid in
1998.

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 $316.3  million at
December  31, 1999 as compared to $1,606.1  million at December  31,  1998.  The
majority of this  decrease was due to the cash used to acquire MHC and the early
retirement of the Senior Discount Notes, the Limited Recourse Notes and the 9.5%
Senior Notes partially offset by the sales of McLeod common stock, the Qualified
Facilities  and the insurance  proceeds on Indonesia.  In addition,  the Company
recorded separately restricted cash and investments of $291.7 million and $637.6
million at December 31, 1999 and December 31, 1998, respectively. The restricted
cash balance as of December 31, 1999 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 debt
service reserve funds.

Berkshire 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  Berkshire
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 nontransferable  trust preferred stock. 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 not more than 9.9% 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 Company incurred  approximately $6.7 million of non-recurring costs in 1999,
related to the Berkshire tranaction, which were expensed.

Financing Activities

The remaining  outstanding Senior Discount Notes of $369.5 million were redeemed
on January 15, 1999 at a redemption price of 105.125% plus accrued interest.

                                      -50-
<PAGE>

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.

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.

On May 18, 1999, CalEnergy Capital Trust, a subsidiary of the Company,  effected
the conversion of $103.9 million of 6 1/4% Convertible Preferred Securities into
approximately 3.5 million shares of common stock of the Company.  The securities
were  converted  at a rate of 1.6728  shares of common  stock of the Company for
each security,  equivalent to a conversion  price of $29.89 per share of Company
common stock.

The Company has  redeemed  substantially  all of the $225  million in  principal
value  of the  9.5%  Senior  Notes  at an  aggregate  price  of  $247.6  million
throughout the year ended December 31, 1999.

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 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-2000.  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.  The  Company has
incurred $92.8 million of such costs through December 31, 1999.

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.

                                      -51-
<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.

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. Accordingly, the Casecnan Project is now expected to become operational by
the second quarter of 2001.

Under the Project Agreement, if NIA has completed certain work on its irrigation
system, CE Casecnan is liable to pay NIA $5,000 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.

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.  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  substantially
denominated in United States  dollars and 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.

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.
Total  project  costs are  estimated to be  approximately  $288.9  million.  The
Company has also  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  output  for sales to  others.  The  construction  of the
Cordova Project is expected to be completed in mid-2001.

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.  Additional  Series A Senior
Secured Bonds will be issued as required to fund  construction.  Cordova Funding
will loan the proceeds to Cordova  Energy as required.  The Company has incurred
$80.0 million of such costs through  December 31, 1999.  Total equity funding is
expected to be approximately $63.9 million.

Evolution of the Domestic Utility Industry

The U.S. utility industry  continues to evolve into an increasingly  competitive
environment.  In  virtually  every  region  of  the  country,   legislative  and
regulatory actions are being taken which result in customers having more choices
in their energy decisions.

                                      -52-
<PAGE>

In the electric industry,  the traditional  vertical  integration of generation,
delivery and marketing is being  unbundled,  with the  generation  and marketing
functions  becoming  deregulated.  For local gas  distribution  businesses,  the
supply, local delivery and marketing functions are similarly being separated and
opened to  competitors  for all  classes of  customers.  While  retail  electric
competition  is  presently  not  permitted  in  Iowa,   MEC's  primary   market,
legislation to do so was introduced in the Iowa legislature in the last session.
While this legislation has not passed,  it is being considered again by the Iowa
legislature in 2000.  Deregulation of the gas supply  function  related to small
volume  customers is also being  considered by the Iowa Utilities Board ("IUB").
MEC is actively participating in the legislative and regulatory processes.

The  generation  and retail  portions of MEC's  electric  business  will be most
affected by competition. The introduction of competition in the wholesale market
has resulted in a proliferation of power marketers and a substantial increase in
market activity.  As retail choice evolves,  competition from other  traditional
utilities,  power marketers and customer-owned  generation could put pressure on
utility margins.

During  the  transition  to  full  competition,   increased  volatility  in  the
marketplace  can be  expected.  With the  elimination  of the energy  adjustment
clause in Iowa,  MEC is  financially  exposed  to  movements  in energy  prices.
Although  MEC  has  sufficient  low  cost  generation  under  typical  operating
conditions for its retail electric  needs, a loss of adequate  generation by MEC
at a time of high market prices could subject MEC to losses on its energy sales.

Domestic Legislative and Regulatory Evolution

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,  beginning October 1, 1999, larger  non-residential  customers in
Illinois and 33% of the remaining non-residential Illinois customers are allowed
to select their provider of electric supply services.  All other non-residential
customers  will have supplier  choice  starting  December 31, 2000.  Residential
customers all receive the  opportunity to select their electric  supplier on May
1, 2002.

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.  A majority of MEC's  electric  and gas
utility  operations  currently  meet the  criteria  required by SFAS 71, but its
applicability is periodically reexamined. On December 16, 1997, MEC's generation
operations  serving Illinois were no longer subject to the provisions of SFAS 71
due to passage of industry restructuring  legislation in Illinois. Thus, in 1997
MEC was required to write off the  regulatory  assets and  liabilities  from its
balance sheet related to its Illinois generation  operations.  The net amount of
such write-offs was not material. If other portions of its utility operations no
longer  meet the  criteria  of SFAS 71, MEC 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, 1999,  the Company had $278.8  million of regulatory  assets on its
consolidated balance sheet.

Domestic Rate Matters: Electric

Through several steps from mid-1997 to the end of 1998, electric prices for Iowa
industrial  customers  were reduced by an amount  which had a $6 million  annual
impact on  revenues,  and electric  prices for Iowa  commercial  customers  were
reduced  by an amount  which had a $4 million  annual  impact on  revenues.  The
reductions  were  achieved  through a retail  access pilot  project,  negotiated
individual  electric  contracts and a $1.5 million  tariffed rate  reduction for
certain non-contract commercial customers.

                                      -53-
<PAGE>

The negotiated electric contracts have differing terms and conditions as well as
prices.  The  contracts  range in length  from five to ten years,  and some have
price  renegotiation  and early  termination  provisions  exercisable  by either
party.  The vast majority of the contracts are for terms of seven years or less,
although, some large customers have agreed to ten-year contracts. 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 MEC incurs to fulfill these
contracts will vary. MEC presently  intends to manage this risk through  hedging
and other similar arrangements.  On an aggregate basis the annual revenues under
contract are approximately $180 million.

Under a 1997  pricing  plan  settlement  agreement  resulting  from an IUB  rate
proceeding, if MEC's annual Iowa electric jurisdictional return on common equity
exceeds 12%, then earnings  above the 12% level will be shared  equally  between
customers and MEC. If the return exceeds 14%, then  two-thirds of MEC's share of
those  earnings  above the 14% level will be used for  accelerated  recovery  of
certain regulatory assets. The pricing plan settlement  agreement  precludes MEC
from filing for increased  rates prior to 2001 unless the return falls below 9%.
Other parties signing the agreement are prohibited from filing for reduced rates
prior to 2001 unless the return, after reflecting credits to customers,  exceeds
14%. On April 14, 1999, the Iowa Utilities Board approved, subject to additional
refund, MEC's calculation of the 1998 return on common equity. During the second
quarter of 1999,  MEC credited $2.2 million to its Iowa  non-contract  customers
related to the return  calculation for 1998. The agreement also eliminated MEC's
energy  adjustment  clause,  and, as a result,  the cost of fuel is not directly
passed on to customers.  In 1999, MEC accrued $15.0 million for customer credits
relating to 1999 operations.

Environmental Matters

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.

MEC 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 MEC has any  responsibility  for remedial action.  MEC's estimate of the
probable  costs for these sites as of December 31, 1999,  was $28 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  matter.  Based on
data to be obtained from monitors  located  throughout the states,  the EPA will
make a  determination  of whether the states have any areas that do not meet the
air quality standards (i.e., areas that are classified as  nonattainment).  If a
state has area(s) classified as nonattainment  area(s), the state is required to
submit a State  Implementation  Plan specifying how it will reach  attainment of
the standards through emission reductions or other means.

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.  The EPA's appeal of the court's  ruling to
the full panel of the U.S. Court of Appeals for the District of Columbia Circuit
was denied.  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



                                      -54-
<PAGE>

the new standards are  implemented,  then MEC's fossil fuel generating  stations
may  be  subject  to  emission   reductions  if  the  stations  are  located  in
nonattainment  areas. As part of an overall state plan to achieve  attainment of
the standards,  MEC could be required to install control equipment on its fossil
fuel  generating  stations or decrease  the number of hours  during  which these
stations  operate.  The degree to which MEC may be required  to install  control
equipment or decrease  operating hours under a  nonattainment  scenario would be
determined by the state's assessment of ME's relative  contribution,  along with
other emission sources, to the nonattainment status. The installation of control
equipment  would result in  increased  costs to MEC. A decrease in the number of
hours during which the affected  stations operate would decrease the revenues of
the Company.

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  $42 million during the period 2000 through 2004 to an
external trust established for the investment of funds for decommissioning  Quad
Cities  Station.  Approximately  65% 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,  MEC makes payments to the Nebraska Public Power District  ("NPPD")
related  to  decommissioning  Cooper.  These  payments  are  reflected  in other
operating expense in the consolidated  statements of operations.  NPPD estimates
call for MEC to pay approximately $57 million to NPPD for Cooper decommissioning
during the period 2000 through  2004.  NPPD invests the funds  predominately  in
U.S. Treasury Bonds and other U.S. Government securities.  Approximately 20% was
invested in domestic corporate debt. MEC's obligation for Cooper decommissioning
may be affected by the actual  plant  shutdown  date and the status of the power
purchase  contract  at that time.  In July 1997,  NPPD filed a lawsuit in United
States  District Court for the District of Nebraska  naming MEC as the defendant
and seeking a declaration  of MEC'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.

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.   The
agreement, which expires annually, was renewed in December 1999, 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,  1999,  approximately  $19
million was accounted for as a loan.

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 power sales contracts with other project  participants,  receipt
of required



                                      -55-
<PAGE>

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 Pronouncement

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 established  accounting and reporting
standards for derivative  instruments  and for hedging  activities.  It requires
that an entity  recognize all derivatives as either assets or liabilities in the
statement of financial  position and measure  those  instruments  at fair value.
This  statement  is effective  for the Company in the first  quarter of the year
2001. The Company is in the process of evaluating the impact of this  accounting
pronouncement.

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.

Interest Rate Risk

At   December   31,   1999,   the  Company  had   fixed-rate   long-term   debt,
Company-obligated  mandatorily  redeemable  convertible  preferred securities of
subsidiary  trusts and  subsidiary-obligated  mandatorily  redeemable  preferred
securities  of  subsidiary  trusts of $5,993.2  million in principal  amount and
having a fair value of $5,825.7  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 $281 million if interest rates were to increase by 10%
from their  levels at December  31,  1999.  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,  1999,  the Company had  floating-rate  obligations  of $670.5
million that expose the Company to the risk of increased interest expense in the
event of increases in short-term  interest  rates. If the floating rates were to
increase  by 10% from  December  31, 1999  levels,  the  Company's  consolidated
interest  expense  for  unhedged  floating-rate  obligations  would  increase by
approximately  $414,000 each month in which such increase  continued  based upon
December 31, 1999 principal balances.

                                      -56-
<PAGE>

Currency Exchange Rate Risk

At December 31, 1999, 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  interest rate swap agreements
that effectively  convert the U.S. dollar fixed interest rate to a fixed rate in
Sterling.  At December 31, 1999,  these  interest  rate swap  agreements  had an
aggregate notional amount of $362 million,  which the Company could terminate at
a cost of  approximately  $12.1  million.  A decrease of 10% in the December 31,
1999  rate of  exchange  of  Sterling  to  dollars  would  increase  the cost of
terminating these swap agreements by approximately $54 million.

Energy Commodity Price Risk

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, 1999,  the notional  amount of executed  CFDs was  approximately
$639.2  million,  representing  approximately  12% of the  expected or committed
transaction  volumes  through March 31, 2004. The fair value of these  contracts
was  approximately  $(11.5) million  discounted at 15%, based upon quoted market
prices at December 31, 1999. A hypothetical  decrease of 10% in the market price
of  electricity  from the December 31, 1999 levels would decrease the fair value
of these contracts by approximately $54.7 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.

                                      -57-
<PAGE>

As of December 31, 1999,  the notional  amount of outstanding  forward  purchase
contracts was approximately  $226.8 million,  representing  approximately 13% of
expected  sales through  December 31, 2007. The fair value of such contracts was
approximately  $(8.2) million discounted at 15%, based upon quoted market prices
at December 31, 1999. A hypothetical  decrease of 10% in the market price of gas
from the December 31, 1999 levels would further decrease the fair value of these
contracts by approximately $17.2 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,
uncertainties  relating  to  domestic  and  international  (and  in  particular,
Indonesia)  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.

                                      -58-
<PAGE>
                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                           CONSOLIDATED BALANCE SHEETS
                                 (IN THOUSANDS)
<TABLE>
<CAPTION>

                                                                      AS OF DECEMBER 31,
                                                                 ---------------------------
                                                                     1999           1998
                                                                 ------------    -----------

<S>                                                              <C>             <C>
ASSETS
------
Current Assets:
  Cash and investments .......................................   $    316,327    $ 1,606,148
  Restricted cash and short term investments .................         36,294         29,395
  Accounts receivable ........................................        600,564        525,102
  Other current assets .......................................        185,128        141,721
                                                                 ------------    -----------
    Total Current Assets .....................................      1,138,313      2,302,366

Property, plant, contracts and equipment, net ................      5,463,329      4,236,039
Excess of cost over fair value of net assets acquired, net ...      2,712,677      1,538,176
Regulatory assets ............................................        278,757             --
Long-term restricted cash and investments.....................        255,440        608,176
Nuclear decommissioning trust fund
  and other marketable securities ............................        226,298              -
Equity investments ...........................................        208,023        125,036
Deferred charges, other investments and other assets .........        483,515        293,731
                                                                 ------------    -----------
  Total Assets ...............................................   $ 10,766,352    $ 9,103,524
                                                                 ============    ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current Liabilities:
  Accounts payable ...........................................   $    449,203    $   305,720
  Other accrued liabilities ..................................        458,667        252,751
  Current portion of long-term debt ..........................        614,725        381,491
                                                                 ------------    -----------
    Total Current Liabilities ................................      1,522,595        939,962

Other long-term accrued liabilities ..........................      1,054,440        756,377
Parent company debt ..........................................      1,856,318      2,645,991
Subsidiary and project debt ..................................      3,642,703      2,712,319
Deferred income taxes ........................................        902,868        543,391
                                                                 ------------    -----------
   Total Liabilities .........................................      8,978,924      7,598,040
                                                                 ------------    -----------

Deferred income ..............................................         65,509         58,468
Minority interest ............................................         29,127             --
Company-obligated mandatorily redeemable convertible
  preferred securities of subsidiary trusts ..................        450,000        553,930
Subsidiary-obligated mandatorily redeemable
  preferred securities of subsidiary trusts ..................        101,598             --
Preferred securities of subsidiaries..........................        146,606         66,033

Commitments and contingencies (Notes 17, 18 and 19)

Stockholders' Equity:
Preferred Stock - authorized 2,000 shares, no par value ......             --             --
Common stock - authorized 180,000 shares no par value;
  82,980 shares issued, 59,944 and 59,605 shares outstanding,
  at December 31, 1999 and 1998, respectively ................             --             --
Additional paid in capital ...................................      1,249,079      1,238,690
Retained earnings ............................................        507,726        340,496
Accumulated other comprehensive income .......................        (12,029)            45
Treasury stock - 23,036 and 23,375 common shares at
  December 31, 1999 and 1998, respectively, at cost ..........       (750,188)      (752,178)
                                                                 ------------    -----------
   Total Stockholders' Equity ................................        994,588        827,053
                                                                 ------------    -----------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ...................   $ 10,766,352    $ 9,103,524
                                                                 ============    ===========
</TABLE>

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

                                      -59-
<PAGE>

                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                    (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>

                                                                   YEAR ENDED DECEMBER 31,
                                                          ----------------------------------------
                                                             1999           1998           1997
                                                          -----------    -----------    -----------
<S>                                                       <C>            <C>            <C>
REVENUE:
  Operating revenue ...................................   $ 4,128,737    $ 2,555,206    $ 2,166,338
  Interest and other income ...........................       131,342        127,505        104,573
  Gains on non-recurring items ........................       138,704             --             --
                                                          -----------    -----------    -----------
TOTAL REVENUES ........................................     4,398,783      2,682,711      2,270,911
                                                          -----------    -----------    -----------

COSTS AND EXPENSES:
  Cost of sales .......................................     2,143,891      1,258,539      1,055,195
  Operating expense ...................................       989,551        471,405        398,538
  Depreciation and amortization .......................       427,690        333,422        276,041
  Loss on equity investment in Casecanan ..............            --             --          5,972
  Interest expense ....................................       496,578        406,084        296,364
  Less interest capitalized ...........................       (70,405)       (58,792)       (45,059)
  Losses on non-recurring items........................        54,409             --         87,000
                                                          -----------    -----------    -----------
TOTAL COSTS AND EXPENSES ..............................     4,041,714      2,410,658      2,074,051
                                                          -----------    -----------    -----------

Income before provision for income taxes ..............       357,069        272,053        196,860
Provision for income taxes ............................        93,475         93,265         99,044
                                                          -----------    -----------    -----------

Income before minority interest .......................       263,594        178,788         97,816
Minority interest .....................................        46,923         41,276         45,993
                                                          -----------    -----------    -----------

INCOME BEFORE EXTRAORDINARY ITEM AND
  CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE..       216,671        137,512         51,823

Extraordinary item, net of tax ........................       (49,441)        (7,146)      (135,850)
Cumulative effect of change in accounting
  principle, net of tax ...............................            --         (3,363)            --
                                                          -----------    -----------    -----------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS ....   $   167,230    $   127,003    $   (84,027)
                                                          ===========    ===========    ===========

INCOME PER SHARE BEFORE EXTRAORDINARY ITEM AND
  CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
   PRINCIPLE - BASIC ..................................   $      3.62    $      2.29    $      0.77
Extraordinary item ....................................          (.83)          (.12)         (2.02)
Cumulative effect of change in accounting principle ...            --           (.06)            --
                                                          -----------    -----------    -----------
INCOME (LOSS) PER SHARE - BASIC .......................   $      2.79    $      2.11    $     (1.25)
                                                          ===========    ===========    ===========
INCOME PER SHARE BEFORE EXTRAORDINARY ITEM AND
   CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
   PRINCIPLE - DILUTED ................................   $      3.28    $      2.15    $      0.75
Extraordinary item ....................................          (.69)          (.10)         (1.97)
Cumulative effect of change in accounting principle ...            --           (.04)            --
                                                          -----------    -----------    -----------
INCOME (LOSS) PER SHARE - DILUTED .....................   $      2.59    $      2.01    $     (1.22)
                                                          ===========    ===========    ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.

                                      -60-

<PAGE>

                      MIDAMERICAN ENERGY HOLDINGS COMPANY
                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
                   For the Three Years Ended December 31, 1999
                                 (In thousands)
<TABLE>
<CAPTION>

                                                                                       ADDITIONAL
                                                                                        COMMON
                                                                             OTHER      STOCK
                              OUTSTANDING           ADDITIONAL               COMPRE-   & OPTIONS               UNEARNED
                                COMMON      COMMON   PAID-IN     RETAINED    HENSIVE   SUBJECT TO   TREASURY   COMPEN-
                                SHARES      STOCK    CAPITAL     EARNINGS    INCOME    REDEMPTION    STOCK     SATION      TOTAL
                              -----------   ------  ----------   --------   --------   ----------  ---------   --------  ---------
<S>                                <C>      <C>     <C>          <C>        <C>        <C>         <C>         <C>       <C>
BALANCE DECEMBER 31, 1996          63,448   $   --  $  567,870   $297,520   $ 29,658   $      --   $  (8,787)  $(5,471)  $880,790

Net loss                               --       --          --    (84,027)        --          --          --        --     (84,027)
Other Comprehensive Income
  Foreign currency translation
  adjustment *                         --       --          --         --    (33,247)         --          --        --     (33,247)
                                                                                                                          --------
Comprehensive loss                                                                                                        (117,274)

Equity offering                    19,100       --     698,604         --         --          --          --        --     698,604
Exercise of stock options and
  other equity transactions           396       --      (2,747)        --         --          --       7,767     5,471      10,491
Purchase of treasury stock         (1,622)      --          --         --         --          --     (55,505)       --     (55,505)
Common stock and options
  subject to redemption                --       --          --         --         --    (654,736)         --        -     (654,736)
Tax benefit from stock plan            --       --       2,956         --         --          --          --        --       2,956
__________________________________________________________________________________________________________________________________
BALANCE DECEMBER 31, 1997          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
__________________________________________________________________________________________________________________________________
* Foreign currency translation adjustment has no tax effect

</TABLE>

The accompanying notes are an integral part of these financial statements

                                      -61-
<PAGE>

                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)
<TABLE>
<CAPTION>

                                                                                    YEAR ENDED DECEMBER 31,
                                                                           -----------------------------------------
                                                                              1999           1998           1997
                                                                           -----------    -----------    -----------
<S>                                                                        <C>            <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ......................................................   $   167,230    $   127,003    $   (84,027)
Adjustments to reconcile net cash flow from operating activities:
   Gains on non-recurring items ........................................      (138,704)            --             --
   Non-recurring charge-asset valuation impairment .....................            --             --         87,000
   Extraordinary item, net of tax ......................................        49,441          7,146             --
   Cumulative effect of change in accounting principle .................            --          3,363             --
   Depreciation and amortization .......................................       363,737        290,794        239,234
   Amortization of excess of cost over fair value of net assets acquired        63,953         42,628         36,807
   Amortization of deferred financing and other costs ..................        18,181         21,723         33,792
   Provision for deferred income taxes .................................       (56,590)        34,332         55,584
   Distributions in excess of (less than) income on equity investments .       (22,796)         6,171          7,892
   Income (loss) applicable to minority interest .......................        14,240          5,313        (35,387)
   Changes in other items:
     Accounts receivable ...............................................        61,209       (135,124)       (34,146)
     Accounts payable, accrued liabilities and deferred income .........        32,917        (41,803)        29,799
                                                                           -----------    -----------    -----------
NET CASH FLOWS FROM OPERATING ACTIVITIES ...............................       552,818        361,546        336,548
                                                                           -----------    -----------    -----------

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of MidAmerican, Kiewit's Interests and Northern,
   net of cash acquired ................................................    (2,501,425)      (500,916)      (632,014)
Proceeds from sale of QF's, net of cash disposed .......................       365,074             --             --
Proceeds from Indonesia settlement .....................................       290,000             --             --
Purchase of marketable securities ......................................       (92,523)            --             --
Proceeds from sale of marketable securities ............................       498,676             --             --
Capital expenditures relating to operating projects ....................      (331,337)      (227,071)      (194,224)
Philippine construction ................................................       (62,059)      (112,263)       (27,334)
Acquisition of U.K. gas assets .........................................       (72,280)       (35,677)            --
Domestic construction and other development costs ......................      (180,683)      (119,916)      (159,091)
Decrease (increase) in restricted cash and investments .................       199,588         20,568       (116,668)
Other ..................................................................       (58,263)       (32,505)        63,270
                                                                           -----------    -----------    -----------
NET CASH FLOWS FROM INVESTING ACTIVITIES ...............................    (1,945,232)    (1,007,780)    (1,066,061)
                                                                           -----------    -----------    -----------

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common and treasury stock
    and exercise of stock options ......................................         5,482          3,412        703,624
Proceeds from convertible preferred securities of subsidiary trusts ....            --             --        450,000
Proceeds from issuance of parent company debt ..........................            --      1,502,243        350,000
Repayment of parent company debt .......................................      (853,420)      (167,285)      (100,000)
Net proceeds from revolver .............................................            --             --        (95,000)
Proceeds from subsidiary and project debt ..............................     1,429,856        464,974        795,658
Repayments of subsidiary and project debt ..............................      (369,016)      (255,711)      (271,618)
Deferred charges relating to debt financing ............................         7,761        (47,205)       (48,395)
Purchase of treasury stock .............................................      (104,847)      (724,791)       (55,505)
Other ..................................................................        (1,176)        21,701         13,142
                                                                           -----------    -----------    -----------
NET CASH FLOWS FROM FINANCING ACTIVITIES ...............................       114,640        797,338      1,741,906
                                                                           -----------    -----------    -----------
Effect of exchange rate changes ........................................       (12,047)         3,634        (33,247)
                                                                           -----------    -----------    -----------
Net increase (decrease) in cash and cash equivalents ...................    (1,289,821)       154,738        979,146
Cash and cash equivalents at beginning of year .........................     1,606,148      1,451,410        472,264
                                                                           -----------    -----------    -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR ...............................   $   316,327    $ 1,606,148    $ 1,451,410
                                                                           ===========    ===========    ===========
Supplemental Disclosures:
Interest paid, net of amount capitalized ...............................   $   439,894    $   341,645    $   316,060
                                                                           ===========    ===========    ===========
Income taxes paid ......................................................   $   130,875    $    53,609    $    44,483
                                                                           ===========    ===========    ===========
</TABLE>

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

                                      -62-
<PAGE>
                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   BUSINESS

MidAmerican Energy Holdings Company,  the successor to CalEnergy  Company,  Inc.
(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 three separate platforms:

MIDAMERICAN

The  MidAmerican  Platform  consists  primarily  of the  Company's  ownership in
MidAmerican   Energy  Company  ("MEC").   MEC  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.  MEC
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, 1999, MEC had 663,500 retail  electric  customers and 638,000
retail natural gas customers.

In addition to retail sales,  MEC 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.

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,
1999, Northern supplied electricity to 1,339,000 customers.

Northern also competes to supply gas inside and outside its authorized  area. In
the residential market Northern currently supplies gas to approximately  570,000
customers and is now the fourth  largest gas supplier of the new entrants in the
U.K. residential market.


                                      -63-
<PAGE>

CALENERGY

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 eight  operating  geothermal  plants in Imperial
Valley,  California and three operating natural gas fired cogeneration plants in
New York,  Texas and  Arizona.  Plant  capacity  factors for  Vulcan,  Hoch (Del
Ranch), Elmore and Leathers (collectively the "Partnership  Projects") are based
on capacity amounts of 34, 38, 38, and 38 net MW,  respectively,  and for Salton
Sea I, Salton Sea II, Salton Sea III and Salton Sea IV plants  (collectively the
"Salton Sea  Projects")  are based on capacity  amounts of 10, 20, 49.8 and 39.6
net MW,  respectively (the Partnership  Projects and the Salton Sea Projects are
collectively  referred to as the "Imperial  Valley  Projects").  Plant  capacity
factors for Saranac,  Power Resources and Yuma  (collectively  the "Gas Plants")
are based on  capacity  amounts  of 240,  200 and 50 net MW,  respectively.  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.

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 less than 50% owned,  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.

CASH EQUIVALENTS, INVESTMENTS AND RESTRICTED CASH

The Company  considers all  investment  instruments  purchased  with an original
maturity of three months or less to be cash equivalents.  Investments other than
restricted  cash are  primarily  commercial  paper and money market  securities.
Restricted cash is not considered a cash equivalent.

The  current   restricted  cash  and  short  term  investment  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 investment  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.


                                      -64-
<PAGE>


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 10
and 30  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 3 to 15 years.

An allowance for the estimated annual  decommissioning  costs of the Quad Cities
Nuclear  Power Station  (Quad Cities  Station)  equal to the level of funding is
included  in  depreciation  expense.  See  Note  18 for  additional  information
regarding decommissioning costs.

In April 1998, the Accounting  Standards Executive Committee issued Statement of
Position (SOP) No. 98-5,  "Reporting on the Costs of Start-Up  Activities."  SOP
No. 98-5 requires  that, at the  effective  date of adoption,  costs of start-up
activities  previously  capitalized  be expensed  and  reported as a  cumulative
effect of a change in accounting principle, and further requires that such costs
subsequent  to  adoption  be expensed as  incurred.  The  Company  adopted  this
standard in 1998 and expensed applicable  unamortized  start-up costs previously
capitalized.  The  cumulative  effect of the change in accounting  principle was
$3.4 million, net of taxes of $2.2 million.

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.

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  MidAmerican  and  Northern  acquisitions,  and a 32  year  period  for  the
acquisition of KDG.

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.


                                      -65-
<PAGE>

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.

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  income  taxes are  provided  for  retained  earnings of  international
subsidiaries and corporate joint ventures that are intended to be remitted.

NET INCOME PER COMMON SHARE

Basic and diluted  earnings per common  share are based on the weighted  average
number of common  shares  outstanding  during the period.  Diluted  earnings per
common share also assumes the conversion of the convertible preferred securities
of subsidiary  trusts,  when  dilutive,  and the exercise of all dilutive  stock
options  outstanding at their option prices,  with the option exercise  proceeds
and tax benefits used to repurchase shares of common stock at the average market
price using the treasury stock method.

A  reconciliation  of basic  earnings  per share before  extraordinary  item and
cumulative  effect of change in  accounting  principle  to diluted  earnings per
share before  extraordinary  item and cumulative  effect of change in accounting
principle follows (in thousands, except per share amounts):

<TABLE>
<CAPTION>
                                                             1999                             1998
                                               -------------------------------   -------------------------------
                                                                     PER SHARE                         PER SHARE
                                                INCOME      SHARES     AMOUNT     INCOME      SHARES    AMOUNT
                                               --------     ------   ---------   --------     ------   ---------

<S>                                            <C>          <C>        <C>       <C>          <C>        <C>
Basic earnings per share before
  extraordinary item and cumulative
  effect of change in accounting principle     $216,671     59,929     $3.62     $137,512     60,139     $2.29
Effect of dilutive securities:
  Stock options ..........................           --        865                     --        634
  Convertible preferred securities of
  subsidiary trusts (1) ..................       19,383     11,154                 21,883     13,327
                                               --------     ------               --------     ------
Diluted earnings per share before
  extraordinary item and cumulative
  effect of change in accounting principle     $236,054     71,948     $3.28     $159,395     74,100     $2.15
                                               ========     ======               ========     ======     ======
</TABLE>

                                      -66-
<PAGE>

                                                          1997
                                             -------------------------------
                                                                   PER SHARE
                                             INCOME      SHARES      AMOUNT
                                             -------     ------    ---------
Basic earnings per share before
  extraordinary item and cumulative
  effect of change in accounting principle.  $51,823     67,268      $0.77
Effect of dilutive securities
  Stock options............................        -      1,418
  Convertible preferred securities of
  subsidiary trusts (1)....................        -          -
                                             -------     ------
Diluted earnings per share before
  extraordinary item and cumulative
  effect of change in accounting principle.  $51,823     68,686      $0.75
                                             =======     ======

(1) The convertible  preferred securities of subsidiary trusts were antidilutive
    in 1997.

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. The Company's practice
is not to hold or  issue  financial  instruments  for  trading  purposes.  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

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 in stockholders'  equity.  Revenues and expenses are
translated at average exchange rates for the year.

Transaction  gains and losses  that arise from  exchange  rate  fluctuations  on
transactions  denominated  in a  currency  other than the  functional  currency,
except those  transactions  which operate as a hedge of an identifiable  foreign
currency commitment or as a hedge of a foreign currency investment position, are
included in the results of operations as incurred.

RECLASSIFICATION

Certain amounts in the fiscal 1998 and 1997  consolidated  financial  statements
and supporting note disclosures have been  reclassified to conform to the fiscal
1999 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
generally accepted  accounting  principles requires management to make estimates
and assumptions  that affect the reported  amounts of assets and liabilities


                                      -67-
<PAGE>

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,  MEC  purchases  one-half  of the  output  of the
778-megawatt  Cooper  Nuclear  Station.  Other  accrued  liabilities  include  a
liability  for MEC's  fixed  obligation  to pay 50% of NPPD's  Nuclear  Facility
Revenue Bonds and other fixed liabilities.

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.  MEC began charging the remaining Cooper capital  improvement costs
to expense for jurisdictions other than Iowa as incurred in January 1997.

The fuel cost  portion of the power  purchase  contract  is included in costs of
sales.  All other costs MEC incurs in relation to its long-term  power  purchase
contract with NPPD are included in operating expense.

NEW ACCOUNTING PRONOUNCEMENT

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 established  accounting and reporting
standards for derivative  instruments  and for hedging  activities.  It requires
that an entity  recognize all derivatives as either assets or liabilities in the
statement of financial  position and measure  those  instruments  at fair value.
This  statement  is effective  for the Company in the first  quarter of the year
2001. The Company is in the process of evaluating the impact of this  accounting
pronouncement.

3. BERKSHIRE 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  Berkshire
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 nontransferable  trust preferred stock. 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 not more than 9.9% 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 Company incurred  approximately $6.7 million of non-recurring costs in 1999,
related to the Berkshire transaction, which were expensed.

4. ACQUISITIONS/DISPOSITIONS

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


                                      -68-
<PAGE>

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  consummation  of the MidAmerican  Merger was conditioned  upon receipt of a
number of regulatory and  shareholder  approvals and the  disposition of partial
interests in certain of the Company's  power  generating  facilities in order to
maintain the qualifying  facilities  status of such independent power generating
facilities. See discussion of Qualified Facilities Dispositions below.

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 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  $1.5  billion,  which  is  being
amortized using the straight-line method over a 40-year period.

Unaudited pro forma  combined  revenue,  income before  extraordinary  item, net
income and basic  earnings  per share of the Company and MHC for the years ended
December 31, 1999 and 1998, as if the  acquisition had occurred at the beginning
of each year after giving effect to certain pro forma adjustments related to the
acquisition and including the sales of the qualified facilities, the issuance of
senior secured notes and bonds and the redemptions of certain  limited  recourse
notes and senior discount  notes,  were $4.81 billion,  $230.6  million,  $181.3
million and $3.03, respectively, compared to $4.13 billion, $97.3 million, $97.3
million and $1.62, respectively.

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 or
$0.17 per diluted share.

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


                                      -69-
<PAGE>

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 or $0.65 per diluted share.

HOMESERVICES.COM

On October 18, 1999, the Company  closed on its initial public  offering of 3.25
million shares of common stock of HomeServices.Com ("HomeServices"),  previously
a wholly-owned  subsidiary of the Company,  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.

KDG

On January 2, 1998,  the Company  completed  the purchase of Kiewit  Diversified
Group's ("KDG")  ownership  interest in various project  partnerships and common
shares of the Company (the "KDG  Acquisition") for a cash price of approximately
$1.16 billion,  including  transaction  costs.  KDG's ownership  interest in the
Company  comprised  approximately  20.2 million shares of common stock (assuming
exercise by KDG of one million options to purchase the Company's  shares), a 30%
interest in  Northern,  as well as the  following  minority  project  interests:
Mahanagdong  (45%),  Casecnan (35%),  Dieng (47%),  Patuha (44%), Bali (30%) and
other interests in international development stage projects.

INDONESIA

On December 2, 1994,  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.

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,
assuming proceeds from political risk insurance and no tax benefits.

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.


                                      -70-
<PAGE>

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  ("MOF") 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  which  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.

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.  Such insurance
covered  expropriation  of the  Company's  investment in HCE and PPL, as well as
material  breaches  by PLN  of  the  ESCs  and  by  the  ROI of its  performance
undertakings.  On November 18, 1999, the Company  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, or $0.81 per diluted share.

5.   PROPERTY, PLANT, CONTRACTS AND EQUIPMENT:

Property,  plant,  contracts and equipment comprise the following at December 31
(in thousands):

<TABLE>
<CAPTION>

                                                         1999           1998
                                                     -----------    -----------
<S>                                                  <C>            <C>
Operating assets:
Utility generation and distribution system ......... $ 3,996,389    $ 1,305,806
Independent power plants ...........................     705,346      1,868,002
Wells and resource development .....................     123,845        473,237
Power sales agreements .............................          --        193,868
Other assets .......................................     377,897        313,029
                                                     -----------    -----------

Total operating assets .............................   5,203,477      4,153,942

Less accumulated depreciation and amortization .....    (695,801)      (769,526)
                                                     -----------    -----------

Net operating assets ...............................   4,507,676      3,384,416

Mineral and gas reserves and exploration assets, net     476,416        375,208
Construction in progress:
     Casecnan ......................................     306,007        243,948
     Zinc recovery project .........................      92,794         24,183
     Cordova .......................................      79,982             --
     Indonesia and other ...........................         454        208,284
                                                     -----------    -----------

TOTAL .............................................. $ 5,463,329    $ 4,236,039
                                                     ===========    ===========
</TABLE>

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.


                                      -71-
<PAGE>


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-2000.  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.

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.

On November  20, 1999,  pursuant to an  amendment  of the Casecnan  Construction
Contract  which  was  approved  by  the  independent  engineer  under  the  Bond
Indenture,  the Guaranteed  Substantial Completion Date for the Casecnan Project
was  extended  to March 31,  2001.  Accordingly,  the  Casecnan  Project  is now
expected to become operational by the second quarter of 2001.

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.
Total  project  costs are  estimated to be  approximately  $288.9  million.  The
Company has also  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  output  for sales to  others.  The  construction  of the
Cordova Project is expected to be completed in mid-2001.


                                      -72-
<PAGE>

6.   PARENT COMPANY DEBT

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

                                                1999         1998
                                             ----------   ----------
     Senior Discount Notes ...............   $       --   $  369,501
     9.5% Senior Notes ...................           32      224,265
     7.63% Senior Notes ..................      350,000      350,000
     Limited Recourse Senior Secured Notes        4,225      200,000
     $1.4 Billion Senior Notes ...........    1,400,000    1,400,000
     $100 Million Senior Notes ...........      102,061      102,225
                                             ----------   ----------
                                             $1,856,318   $2,645,991
                                             ==========   ==========

SENIOR DISCOUNT NOTES

In March 1994, the Company  issued $400 million of 10.25% Senior  Discount Notes
which accreted to an aggregate principal amount of $529.6 million at maturity in
2004.  The original  issue  discount was  amortized  from the issue date through
January 15,  1997,  during  which time no cash  interest  was paid on the Senior
Discount  Notes.  Cash  interest  on  the  Senior  Discount  Notes  was  payable
semiannually  on January 15 and July 15 of each year,  commencing July 15, 1997.
During 1998, the Company  repurchased and retired $160.1 million of the notes at
an average price of 106.173% plus accrued interest.  The remainder of the Senior
Discount  Notes were  subsequently  redeemed on January 15, 1999 at a redemption
price of 105.125% plus accrued interest.  Due to the early extinguishment of the
Senior Discount Notes, the Company recorded extraordinary losses, net of tax, of
$14.0 million and $7.1 million in 1999 and 1998 respectively.

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 is  payable  on June 30 and  December  30 of each year,
commencing  December  1995.  The  Limited  Recourse  Notes  are  secured  by  an
assignment and pledge of 100% of the outstanding  capital stock of Magma and are
recourse  only to such Magma  capital  stock and  general  assets of the Company
equal  to the  Restricted  Payment  Recourse  Amount,  as  defined  in the  Note
Indenture ("Note Indenture"), which was $0 at December 31, 1999.

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


                                      -73-
<PAGE>


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 or after June 30, 2000,
the  remaining  Limited  Recourse  Notes  are  redeemable  at the  option of the
Company,  in whole or in part,  initially  at a  redemption  price of  104.9375%
declining to 100% on June 30, 2002 and thereafter,  plus accrued interest to the
date of redemption. The Company expects to redeem the remaining Limited Recourse
Notes on or about June 30, 2000.

$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.

$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.

REVOLVING CREDIT FACILITY

The Company has available a $400 million  revolving credit facility  expiring in
November  2000.  The  facility is  unsecured  and is  available  to fund working
capital requirements and finance future business expansion opportunities.  There
was no outstanding  balance under this revolving  credit facility as of December
31, 1999.

7.   SUBSIDIARY AND PROJECT DEBT

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

<TABLE>
<CAPTION>

                                                                    1999         1998
                                                                 ----------   ----------
<S>                                                              <C>          <C>
MidAmerican Funding, LLC Senior Notes and Bonds ..............   $  702,089   $       --
MEC Mortgage Bonds ...........................................      450,570           --
MEC Pollution Control Bonds ..................................      157,129           --
MEC Notes ....................................................      262,240           --
MEC Commercial Paper .........................................      204,000           --
MidAmerican Capital Notes ....................................       70,098           --
HomeServices Senior Notes and Revolving Debt .................       48,817           --
Salton Sea Notes and Bonds ...................................      140,520      626,816
Northern Eurobonds ...........................................      324,850      426,785
CE Electric UK Funding Company Senior Notes and Sterling Bonds      670,327      684,986
Casecnan Notes and Bonds .....................................      363,085      371,500
Philippine Term Loans ........................................      449,739      517,998
Northern Short Term Treasury Loan ............................      174,593       72,740
Cordova Funding Senior Secured Bonds .........................      124,824           --
CE Gas Loan ..................................................      113,267       41,355
CE Indonesia Funding Corp. Construction Loans, Power
  Resources and Coso Funding Corp. Project Debt and Other ....        1,280      351,630
                                                                 ----------   ----------
                                                                 $4,257,428   $3,093,810
                                                                 ==========   ==========
</TABLE>



                                      -74-
<PAGE>

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, MHC, HomeServices 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.

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.

MEC MORTGAGE BONDS, POLLUTION CONTROL BONDS AND NOTES

The components of MEC's  Mortgage  Bonds,  Pollution  Control Bonds and Notes at
December 31, 1999 are as follows (in thousands):

Mortgage bonds:
    6% Series, due 2000.........................................    $ 35,000
    6.75% Series, due 2000......................................      75,000
    7.125% Series, due 2003.....................................     100,000
    7.70% Series, due 2004......................................      55,630
    7% Series, due 2005.........................................      90,500
    7.375% Series, due 2008.....................................      75,000
    7.45% Series, due 2023......................................       6,940
    6.95% Series, due 2025......................................      12,500
                                                                    --------
                                                                    $450,570
                                                                    ========

Pollution control revenue obligations:
    5.75% Series, due periodically through 2003.................    $  7,704
    5.95% Series, due 2023 (secured by general mortgage bonds)..      29,030
    Variable rate series -
       Due 2016 and 2017, 3.95% ................................      37,600
       Due 2023 (secured by general mortgage bond, 3.95%).......      28,295
       Due 2023, 3.95%..........................................       6,850
       Due 2024, 3.95%..........................................      34,900
       Due 2025, 3.95%..........................................      12,750
                                                                    --------
                                                                    $157,129
                                                                    ========

Notes:
    8.75% Series, due 2002......................................    $    240
    6.5% Series, due 2001.......................................     100,000
    6.375% Series, due 2006.....................................     160,000
    6.7% Series, due 2003.......................................       1,000
    6.1% Series, due 2007.......................................       1,000
                                                                    --------
                                                                    $262,240
                                                                    ========

MEC COMMERCIAL PAPER

MEC 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 for interim  financing of working capital needs. As of December 31,
1999,  MEC had a $250  million  revolving  credit  facility  and lines of credit
totaling $95 million

                                      -75-
<PAGE>

and MHC had  lines of  credit  totaling  $24  million.  MEC's  commercial  paper
borrowings  are  supported  by the  revolving  credit  facility and the lines of
credit.  As of December 31, 1999,  commercial  paper and bank notes totaled $204
million for MEC with a weighted average interest rate of 6.3%.

MIDAMERICAN CAPITAL NOTES

MidAmerican Capital Company, a wholly owned subsidiary of the Company,  has debt
of $70 million of 8.52% Senior Notes.  These notes are due in annual  increments
of $23.3 million beginning in 2000 with final payment in 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 $75
million senior secured revolving credit facility of which HomeServices had drawn
down $11 million as of December 31, 1999.  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, 1999, the blended average interest
rate on the senior secured revolving credit facility borrowings was 8.08%.

SALTON SEA NOTES AND BONDS

As the Company's  interest in Salton Sea Funding  Corporation was transferred to
CE Generation, the balance of Salton Sea Notes and Bonds as of December 31, 1998
of  $626.8  million  is  included  in  the  Company's  equity  investment  in CE
Generation  as of December 31, 1999.  However,  the Company  retained  CalEnergy
Minerals LLC, which is one of the guarantors of this debt. As a result of a note
allocation  agreement,  CalEnergy  Minerals  LLC is  primarily  responsible  for
$140.52  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 the current  principal  amount of $140.52
million and associated interest.

NORTHERN EUROBONDS

The  balance  at  December  31,  1999 and 1998  consists  of the  following  (in
thousands):

                                                  1999             1998
                                                --------         --------
12.661% Debenture due 1999 ...................  $     --         $ 94,393
8.625% Bearer bonds due 2005 .................   162,512          166,286
8.875% Bearer bonds due 2020 .................   162,338          166,106
                                                --------         --------
                                                $324,850         $426,785
                                                ========         ========

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):

                                                  1999             1998
                                                --------         --------
6.853% Senior Notes due 2004 .................  $121,754         $124,376
6.995% Senior Notes due 2007 .................   230,662          235,694
7.25% Sterling Bonds due 2022 ................   317,911          324,916
                                                --------         --------
                                                $670,327         $684,986
                                                ========         ========

                                      -76-
<PAGE>

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.

On December  15,  1997,  CE Electric UK Funding  Company  entered  into  certain
interest  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 is approximately  $12.1 million based on quotes from the counterparty
to these  instruments and represents the estimated amount that the Company would
expect to pay to terminate these  agreements.  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 $75 million
Senior  Secured  Floating  Rate Notes (FRNs) due in 2002;  $125  million  Senior
Secured Series A Notes (Series A Notes) with interest at 11.45% due in 2005; and
$171.5  million  Senior Secured Series B Bonds (Series B Bonds) with interest at
11.95%  due in 2010.  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.  During 1999,  the Company  purchased
$8.4 million of the FRNs.

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
(8.37% at December 31, 1999). 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  (9.10% at  December  31,  1999).  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.

NORTHERN SHORT TERM TREASURY LOAN

Northern  had  short-term  money  market loans in place at December 31, 1999 and
1998 of $174.6 million and $72.7 million, respectively. The amounts have varying
maturities generally less than one month and carry variable interest rates based
on LIBOR and ranging from 5.58% to 6.19% at December 31, 1999.

                                      -77-
<PAGE>

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.  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 due in 2019 were issued on December 15, 1999.  Additional Series A
Senior  Secured Bonds will be issued as required to fund  construction.  Cordova
Funding will loan the proceeds to Cordova Energy as required.

CE GAS LOAN

CE Gas, a wholly owned  subsidiary of the Company,  had borrowed  $113.3 million
and $41.4 million on a 70 million pounds sterling revolving facility at December
31, 1999 and 1998, respectively,  to fund the purchases of certain UK gas assets
in the North Sea.  The amount  carries a variable  interest  rate based on LIBOR
(7.055% at December 31, 1999). The revolving facility was completely utilized at
December 31, 1999.

ANNUAL REPAYMENTS OF SUBSIDIARY AND PROJECT DEBT

The annual repayments of the subsidiary and project debt for the years beginning
January 1, 2000 and thereafter are as follows (in thousands):

<TABLE>
<CAPTION>

               MIDAMERICAN                                     MIDAMERICAN
                 FUNDING,                     MIDAMERICAN      ENERGY NOTES,
                  LLC        MIDAMERICAN        ENERGY          COMMERCIAL      HOMESERVICES
                 SENIOR        ENERGY          POLLUTION          PAPER &        SENIOR NOTES     SALTON
                NOTES AND     MORTGAGE          CONTROL         MIDAMERICAN     AND REVOLVING       SEA         NORTHERN
                  BONDS         BONDS             BONDS         CAPITAL NOTES        DEBT          BONDS        EUROBONDS
                ---------    -----------      -----------       -------------   -------------     --------      ---------
<S>              <C>           <C>              <C>                <C>             <C>            <C>           <C>
2000             $      -      $110,000         $    504           $227,578        $   707        $      -      $       -
2001              200,000             -            1,440            123,333            730             632              -
2002                    -             -            1,440             23,574         11,694           2,108              -
2003                    -       100,000            5,320                  -            482           1,405              -
2004                    -        55,630                -                  -          5,084           1,757              -
Thereafter        502,089       184,940          148,425            162,203         30,120         134,618        324,850
                 --------      --------         --------          ---------        -------        --------       --------
                 $702,089      $450,570         $157,129           $536,688        $48,817        $140,520       $324,850
                 ========      ========         ========           ========        =======        ========       ========

</TABLE>

<TABLE>
<CAPTION>


              CE ELECTRIC UK
              FUNDING COMPANY                  NORTHERN                                           CORDOVA
                  SENIOR                       SHORT TERM                                          FUNDING
                 NOTES AND                     TREASURY            CASECNAN       PHILIPPINE       SENIOR
                 STERLING          CE           LOAN              NOTES AND         TERM          SECURED
                   BONDS        GAS LOAN       AND OTHER             BONDS          LOANS           BONDS          TOTAL
              --------------   ---------     -----------         ----------      ----------       --------     ----------
<S>              <C>           <C>            <C>                 <C>            <C>              <C>          <C>
2000             $      -      $ 15,508       $  175,523          $  16,646      $  68,259        $      -     $  614,725
2001                    -        19,340                -             26,301         68,259               -        440,035
2002                    -        17,553                -             32,213         68,259             699        157,540
2003                    -        21,640                -             41,468         72,148           4,993        247,456
2004              121,754        21,045                -             49,360         67,148           4,494        326,272
Thereafter        548,573        18,181                -            197,097        105,666         114,638      2,471,400
                 --------      --------       ----------          ---------      ---------        --------     ----------
                 $670,327      $113,267       $  175,523          $ 363,085      $ 449,739        $124,824     $4,257,428
                 ========      ========       ==========          =========      =========        ========     ==========
</TABLE>


                                      -78-
<PAGE>

8.   INCOME TAXES

Provision  for income taxes was  comprised  of the  following at December 31 (in
thousands):

                          1999         1998       1997
                        --------     -------    --------
Current:
  State ............    $  7,337     $ 5,677    $  5,084
  Federal ..........     128,839      33,160      33,114
  Foreign ..........      13,889      20,096       5,262
                        --------     -------    --------
                         150,065      58,933      43,460
                        --------     -------    --------
Deferred:
  State ............       1,791         161        (264)
  Federal ..........     (75,510)     14,973      14,579
  Foreign ..........      17,129      19,198      41,269
                        --------     -------    --------
                         (56,590)     34,332      55,584
                        --------     -------    --------
  Total ............    $ 93,475     $93,265    $ 99,044
                        ========     =======    ========

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

                                                    1999       1998       1997
                                                   -----      -----      -----
Federal statutory rate .........................   35.00%     35.00%     35.00%
Percentage depletion in excess of cost depletion    (.38)     (3.52)     (3.77)
Investment and energy tax credits ..............   (1.78)      (.93)      (.64)
State taxes, net of federal tax effect .........    1.66       1.71       1.59
Goodwill amortization ..........................    5.46       2.51       2.06
Dividends on preferred
    securities of subsidiary trusts* ...........   (3.75)     (4.63)     (4.12)
Tax effect of foreign income ...................     .36       1.86       2.64
Non-recurring items on Indonesia ...............  (10.99)        --      15.47
Other ..........................................     .60       2.28       2.08
                                                   -----      -----      -----
Effective tax rate .............................   26.18%     34.28%     50.31%
                                                   =====      =====      =====

*  Dividends  on  convertible  and  non-convertible   preferred   securities  of
subsidiary trusts are included in minority interest.

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

                                                       1999            1998
                                                    -----------     ---------
Depreciation and amortization, net ...............  $   983,038     $ 769,376
Income taxes recoverable through future rates ....      187,379            --
Demand side management ...........................       14,805            --
Reacquired debt ..................................       12,476            --
Pensions/profit sharing ..........................           --        22,305
Unremitted foreign earnings ......................           --        25,393
                                                    -----------     ---------
                                                      1,197,698       817,074
                                                    -----------     ---------

Nuclear reserve and decommissioning ..............      (20,280)           --
Deferred income ..................................      (19,502)       (9,458)
Deferred contract costs ..........................     (215,388)     (182,745)
General business tax credits .....................           --       (21,300)
Alternative minimum tax credits ..................           --       (44,452)
Accruals not currently deductible for tax purposes      (32,211)      (11,591)
Other ............................................       (7,449)       (4,137)
                                                    -----------     ---------
                                                       (294,830)     (273,683)
                                                    -----------     ---------
Net deferred income taxes ........................  $   902,868     $ 543,391
                                                    ===========     =========

                                      -79-
<PAGE>

9.   COMPANY-OBLIGATED  MANDATORILY  REDEEMABLE CONVERTIBLE 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

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 Convertible  Subordinated  Debentures
due March 10, 2016,  February 25, 2012 and September 1, 2027,  respectively,  in
outstanding aggregate principal amounts of $103.9 million, $180 million and $270
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  Berkshire
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 Berkshire  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.

Until converted into the company's  common stock, the Trust Securities will have
no voting rights with respect to the Company and,  except under certain  limited
circumstances,   will  have  no  voting  rights  with  respect  to  the  Trusts.
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.

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.

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.

10.  SUBSIDIARY-OBLIGATED   MANDATORILY   REDEEMABLE   PREFERRED  SECURITIES  OF
     SUBSIDIARY TRUST

In December  1996,  MidAmerican  Energy  Financing I, a wholly  owned  statutory
business trust of MEC,  issued  4,000,000  shares of 7.98% Series  MEC-obligated
mandatorily  redeemable  preferred  securities . The sole assets of  MidAmerican
Energy  Financing are $103.1  million of MEC 7.98% Series A Debentures  due 2045
(the  "Debentures").  There  is a full  and  unconditional  guarantee  by MEC of
MidAmerican Energy Financing's  obligations under the preferred securities.  MEC
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


                                      -80-
<PAGE>

continue to accrue  with  interest  thereon,  and MEC may not declare or pay any
dividend or other  distribution  on, or redeem or  purchase,  any of its capital
stock.

The  Debentures  may be redeemed by MEC 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.

11.  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  Berkshire
transaction  was  approved  by the Board of  Directors  and did not  trigger the
dividend of a preferred share purchase right.

12.  STOCK OPTIONS AND RESTRICTED STOCK

The Company has 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  allow  options to be granted at 85% of their fair  market
value of the common stock at the date of grant. Generally, options are issued at
100% of fair  market  value of the  common  stock at the date of grant.  Options
granted  under the 1996  plan  become  exercisable  over a period of two to five
years and expire if not exercised within ten years from the date of grant or, in
some  instances,  a lesser term. As a result of the Berkshire  transaction,  all
options, except for David Sokol's and Greg Abel's, were cashed out at $35.05 per
share.

The Company  granted 500 shares of  restricted  common  stock with an  aggregate
market  value of $9.5 million in exchange  for the  relinquishment  of 500 stock
options  that were  canceled  by the  Company.  The shares  have all rights of a
shareholder,  subject to certain  restrictions  on  transferability  and risk of
forfeiture.  Unearned compensation  equivalent to the market value of the shares
at the date of  issuance  was charged to  stockholders'  equity.  Such  unearned
compensation  was  amortized  over the  vesting  period of which 125 shares were
immediately  vested and the remaining 375 shares vested through January 1, 1998.
Accordingly,  $5.5  million of unearned  compensation  was charged to  operating
expense in 1997.


                                      -81-
<PAGE>


TRANSACTIONS IN STOCK OPTIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>

                                        SHARES                               OPTIONS OUTSTANDING
                                      AVAILABLE                 -------------------------------------------
                                      FOR GRANT
                                      UNDER 1996                  OPTION PRICE     WEIGHTED AVG.
                                     OPTION PLAN    SHARES         PER SHARE       OPTION PRICE     TOTAL
                                     -----------    ------      ----------------   -------------  --------
<S>                                   <C>            <C>        <C>      <C>          <C>         <C>
Balance December 31, 1996 ..........     311         4,777      $ 3.00 - $ 30.38      $ 17.92     $ 85,585
     Options granted ...............  (2,307)        2,513       29.06 -   40.81        34.80       87,457
     Options terminated ............     165          (165)       3.00 -   29.06        20.04       (3,307)
     Options exercised .............      --          (345)       3.74 -   29.06        13.28       (4,583)
     Additional shares reserved
        under 1996 Option Plan .....   2,000            --          --        --           --           --
                                      ____________________________________________________________________

Balance December 31, 1997 ..........     169         6,780        3.74 -   40.81        24.36      165,152
     Revaluation ...................      --            --       29.00 -   40.81        --         (16,011)
     Options granted ...............    (405)          405       24.22 -   28.75        24.61        9,968
     Options terminated ............     311        (1,311)       3.74 -   25.06        14.71      (19,284)
     Options exercised .............      --          (164)       3.74 -   24.70        11.41       (1,872)
     Additional shares reserved
        under 1996 Option Plan .....   1,000            --          --        --           --           --
                                      ____________________________________________________________________
Balance December 31, 1998 ..........   1,075         5,710        9.71 -   34.69        24.16      137,953
     Options granted ...............  (1,106)        1,106       15.10 -   32.56        28.88       31,937
     Options terminated ............     386          (386)       9.71 -   34.69        27.72      (10,689)
     Options exercised .............      --          (171)       9.71 -   26.29        17.68       (3,018)
                                      ____________________________________________________________________
Balance December 31, 1999 ..........     355         6,259       $9.71 -  $34.69      $ 24.95     $156,183
                                      ____________________________________________________________________

Options exercisable at:
     December 31, 1997                               3,665       $3.74 -  $40.19      $ 18.12     $ 66,425
     December 31, 1998                               3,167       $9.71 -  $34.56      $ 20.55     $ 65,097
     December 31, 1999                               3,776       $9.71 -  $34.56      $ 22.17     $ 83,708
</TABLE>

During 1998, the Company  revalued  certain of its stock options granted in 1996
and 1997 and reduced the exercise price of those options by 15%.

The following table summarizes  information about stock options  outstanding and
exercisable as of December 31, 1999 (in thousands, except per share amounts):

                                            WEIGHTED
                               WEIGHTED      AVERAGE                    WEIGHTED
    RANGE OF                   AVERAGE      REMAINING                    AVERAGE
    EXERCISED      NUMBER      EXERCISE    CONTRACTUAL     NUMBER       EXERCISE
    PRICES       OUTSTANDING    PRICE         LIFE       EXERCISABLE     PRICE
---------------   -----------  --------    -----------   -----------    --------
$ 9.71   $18.99      1,531      $16.23       4 years       1,529        $16.23
 19.00    24.99      1,298       21.30       6 years         906         21.30
 25.00    28.99      1,224       28.41       8 years         615         28.42
 29.00    34.69      2,206       31.81       9 years         726         31.73
                     -----                                 -----
                     6,259       24.96       7 years       3,776         22.17
                     =====                                 =====

The Company  applies the  intrinsic  value based  method of  accounting  for its
stock-based employee compensation plans. If the fair value based method had been
applied, non-cash compensation expense and the effect on net income available to
common  stockholders and earnings per share would have been  approximately  $5.5
million or $0.09 per


                                      -82-
<PAGE>



share in 1999,  $4.8 million,  or $0.08 per share for 1998 and $3.6 million,  or
$0.05 per share for 1997.  The fair value for stock options was estimated  using
the  Black-Scholes  option pricing model with the weighted average fair value of
options  granted  during  1999,  1998 and 1997 of  $11.17,  $7.71  and $9.55 per
option, respectively using the following assumptions:

                                        1999           1998           1997
                                        ----           ----           ----
     Risk-fee interest rate            5.10%          5.10%          5.50%
     Expected volatility              31.50%         34.50%         25.00%
     Expected life                 4.8 years      3.4 years      3.7 years
     Expected dividends                   0%             0%             0%

13.  EQUITY OFFERING

On October 17, 1997, the Company  completed the public  offering of 17.1 million
shares of its common  stock at $37 7/8 per share  (the  "Public  Offering").  In
addition,  2 million shares of common stock were purchased from the Company in a
direct  sale by a trust  affiliated  with  Walter  Scott  (the  "Direct  Sale"),
contemporaneously  with the closing of the Public  Offering.  Proceeds  from the
Public Offering and the Direct Sale were approximately $699.9 million.

14.  UK WINDFALL TAX

On July 31, 1997, the Finance Act in the United Kingdom was passed by Parliament
and included the  introduction  of a one time so-called  "windfall tax" equal to
23% of the difference between the price paid for Northern upon privatization and
the Labour government's  assessed "value" of Northern as calculated by reference
to a formula set forth in the July 1997 budget. This amounted to $135.9 million,
net  of  minority   interest  of  $58.2  million,   which  was  recorded  as  an
extraordinary  item.  The first  installment  was paid  December 1, 1997 and the
remainder was paid in 1998.

15.  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 which the Company
could realize in a current transaction.

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 and CE  Indonesia  Funding
Corp. construction 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.


                                      -83-
<PAGE>

<TABLE>
<CAPTION>

                                                                  1999                    1998
                                                                  ----                    ----
                                                                      ESTIMATED                ESTIMATED
                                                         CARRYING       FAIR      CARRYING        FAIR
                                                          VALUE         VALUE       VALUE        VALUE
                                                        ----------   -----------  ----------   ---------
                                                                          (IN THOUSANDS)

<S>                                                     <C>          <C>          <C>          <C>
Senior Discount Notes                                   $       --   $       --   $  369,501   $  388,438
9.5% Senior Notes                                               32           34      224,265      243,328
7.63% Senior Notes                                         350,000      346,220      350,000      372,365
Limited Recourse Senior Secured Notes                        4,225        4,449      200,000      217,900
$1.4 Billion Senior Notes                                1,400,000    1,396,360    1,400,000    1,495,742
$100 Million Senior Notes                                  102,061       97,920      102,225      111,973
MidAmerican Funding, LLC Senior Notes and Bonds            702,089      638,101           --           --
MEC Mortgage Bonds                                         450,570      445,502           --           --
MEC Pollution Control Bonds                                157,129      157,868           --           --
MEC Notes                                                  262,240      249,084           --           --
MEC Commercial Paper                                       204,000      204,000           --           --
MidAmerican Capital Notes                                   70,098       71,526           --           --
HomeServices Senior Notes and Revolving Debt                48,817       44,862           --           --
Saton Sea Bonds                                            140,520      128,815      626,816      646,397
Northern Eurobonds                                         324,850      379,987      426,785      516,080
CE Electric UK Funding Company Senior Notes
    and Sterling Notes                                     670,327      671,779      684,986      772,900
Casecnan Notes and Bonds                                   363,085      353,789      371,500      302,248
Northern Short Term Treasury Loan                          174,593      174,593       72,740       72,740
Cordova Funding Senior Secured Bonds                       124,824      120,399           --           --
CE Gas Loan                                                113,267      113,267       41,355       41,355
Power Resources Project Debt, Coso
   Funding Corp. Project Loans and Other                     1,280        1,280      159,152      162,575
Convertible Preferred Securities of Subsidiary Trusts      450,000      353,925      553,930      562,012
Preferred Securities of Subsidiary Trusts                  101,598       87,240           --           --
Preferred Securities of Subsidiaries                       146,606      135,216       66,033       66,033
</TABLE>


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):

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


                                      -84-
<PAGE>

16.  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, 2000. The
changes  to the  formula  took  effect  from  April 1,  1995 and  April 1,  1996
resulting in one-time reductions in allowed income per unit distributed of about
17% and  13%,  respectively,  with  continuing  real  reductions  in each of the
subsequent  three years 1997/98 to 1999/2000.  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.

In December 1999 Northern  accepted Ofgem's  proposals for the next distribution
price  control  period  which will bring about a further  one-time  reduction of
around 24% in regulated  distribution income with effect from April 1, 2000 with
continuing Xd of 3% in each subsequent year.

As a result of the distribution price reviews,  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.  The Company  recorded a  non-recurring  pre-tax loss of  approximately
$47.7 million and an after-tax loss of approximately  $29.2 million or $0.41 per
diluted share in 1999 due to costs  associated  with the reduction of Northern's
workforce.

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, 2000. The current formula took effect on April 1, 1998 and required
Northern to reduce prices to those customers from the level prevailing at August
1, 1997 by about 4.2% (minus  inflation)  from April 1, 1998 and by a further 3%
(minus inflation) from April 1, 1999.

In December 1999,  Northern accepted Ofgem's proposals for the next supply price
control  period to be effective from April 1, 2000 until March 31, 2002. The new
control  relates to  domestic  customers  only and will lead to a further  price
reduction  for those  customers of 10.8% in real terms with effect from April 1,
2000.

The market for  electricity  supplied to customers with demands of over 1 MW was
opened to competition in 1990. In 1994, this limit was reduced to 0.1 MW. During
1998,  liberalization of the entire market commenced in stages and was completed
during 1999.

MEC

As a result of a negotiated  settlement  in  Illinois,  MEC reduced its Illinois
electric  service  rates by annual  amounts of $13.1  million and $2.4  million,
effective November 3, 1996, and June 1, 1997,  respectively.  MEC implemented an
additional  $0.9 million  annual rate  reduction  for its  Illinois  residential
customers,  effective  August 1, 1998, in  connection  with  Illinois'  electric
utility restructuring law.

On June 27, 1997,  the Iowa  Utilities  Board  approved a March 1997  settlement
agreement  between MEC, the Iowa Office of Consumer  Advocate and other parties.
Four major components of the settlement and their status are as follows:

1) On an annualized  basis,  prices for residential  customers were reduced $8.5
million,  $10.0 million and $5.0 million  effective  November 1, 1996,  July 11,
1997,  and June 1, 1998,  respectively,  for a total  annual  decrease  of $23.5
million.


                                      -85-
<PAGE>


2) Prices for  industrial  customers  were  reduced by $6 million  annually  and
prices for  commercial  customers were reduced by $4 million  annually.  MEC was
given  permission to implement  these  reductions  through a retail access pilot
project,  negotiated  individual  contracts  and tariffed  rate  reductions.  On
January 1, 1999,  MEC reduced  base rates for selected  non-contract  commercial
customers by  approximately  $1.5 million  annually,  subject to Iowa  Utilities
Board approval.  The remainder of the commercial and industrial price reductions
were achieved through negotiated contracts and a retail access pilot project.

The negotiated  contracts have differing terms and conditions as well as prices.
The  contracts  range in length  from  five to ten  years,  and some have  price
renegotiation and early termination  provisions exercisable by either party. The
vast majority of the  contracts are for terms of seven years or less,  although,
some large customers have agreed to 10-year  contracts.  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 MEC  incurs to  fulfill  these
contracts  will vary. On an aggregate  basis the annual  revenues under contract
are approximately $180 million.

3) The Iowa energy adjustment clause was eliminated. Prior to July 11, 1997, MEC
collected  fuel costs from Iowa  customers on a current basis through the energy
adjustment clause,  and thus, fuel costs had little impact on net income.  Since
then,  base  rates  for Iowa  customers  include  a  factor  for  recovery  of a
representative level of fuel costs. If the actual per-unit fuel cost varies from
that  factor,  pre-tax  earnings  are  affected.  The fuel cost factor was to be
reviewed in February  1999 and  adjusted  prospectively  if the actual 1998 fuel
cost per unit varied by more than 15% above or below the factor included in base
rates.  Based on 1998  actual fuel  costs,  MEC  reduced the fuel cost  recovery
factor  in 1999  base  rates  effective  March 1,  1999.  The  estimated  annual
reduction in revenues associated with this adjustment is $1.1 million.

4) If MEC's annual Iowa electric  jurisdictional return on common equity exceeds
12%, an equal sharing between  customers and  shareholders of earnings above the
12% level begins; if it exceeds 14%, two-thirds of MEC's share of those earnings
will be used for  accelerated  recovery  of  regulatory  assets.  The  agreement
precludes MEC from filing for increased rates prior to 2001 unless the return on
common equity falls below 9%. Other parties signing the agreement are prohibited
from filing for reduced rates prior to 2001 unless the return on common  equity,
after reflecting credits to customers, exceeds 14%.

Under a  restructuring  law enacted in 1997, a similar  sharing  mechanism is in
place for Illinois operations. Two-year average returns on common equity greater
than a two-year  average  benchmark will trigger an equal sharing of earnings on
the excess.  The benchmark is a  calculation  of average  30-year  Treasury Bond
rates plus 5.5% for 1998 and 1999 and 8.5% for 2000  through  2004.  The initial
calculation, due March 31, 2000, will be based on 1998 and 1999 results.

17.  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, 1999, 1998 and 1997 assumed interest
rates of 6.0%, 5.5% and 6.75% respectively, an expected return on plan assets of
6.5%, 6.0% and 7.25%,  respectively,  and annual compensation increases of 3.0%,
3.5% and 4.75%,  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.


                                      -86-
<PAGE>


The following  table details the funded status and the amount  recognized in the
consolidated balance sheets for Northern's plan as of December 31, 1999 and 1998
(in thousands):

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

Change in benefit obligation:
Benefit obligation at beginning of year ..........   $   926,000    $   888,500
Service cost .....................................        10,200         12,600
Interest cost ....................................        48,500         58,800
Participant contributions ........................         5,700          5,800
Benefits paid ....................................       (53,700)       (46,700)
FAS 88 curtailment ...............................        38,300             --
Experience loss (gain) and change of assumptions .       (34,400)         7,000
                                                     -----------    -----------
Benefit obligation at end of the year ............       940,600        926,000
                                                     -----------    -----------

Change in plan assets:
Fair value of plan assets at beginning of the year     1,143,100      1,012,600
Actual return on plan assets .....................       181,600        154,200
Contributions ....................................        12,600         23,000
Benefits paid ....................................       (53,700)       (46,700)
                                                     -----------    -----------
Fair value of plan assets at end of the year .....     1,283,600      1,143,100
                                                     -----------    -----------

Funded status ....................................       343,000        217,100
Unrecognized net gain ............................       300,100        140,200
                                                     -----------    -----------
Prepaid benefit cost .............................   $    42,900    $    76,900
                                                     ===========    ===========

As a result of the distribution price reviews,  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.  The Company  recorded a  non-recurring  pre-tax loss of  approximately
$47.7 million which included a pension curtailment of $38.3 million.

Net periodic  pension cost (benefit) for Northern's plan for 1999, 1998 and 1997
included the following components (in thousands):

<TABLE>
<CAPTION>

                                                    1999       1998       1997
                                                  -------    -------   --------

<S>                                               <C>        <C>       <C>
Service cost - benefits earned during the period. $10,200    $12,600   $ 12,600
Interest cost on projected benefit obligation....  48,500     58,800     62,400
Actual return on plan assets..................... (59,500)   (68,000)   (71,400)
                                                  -------    -------   --------
Net periodic pension cost (benefit).............. $  (800)   $ 3,400   $  3,600
                                                  =======    =======   ========
</TABLE>

DOMESTIC OPERATIONS

The Company has primarily  noncontributory  cash balance defined benefit pension
plans covering substantially all 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.

MEC currently  provides certain health care and life insurance  (postretirement)
benefits  for retired  employees.  Under the plans,  substantially  all of MEC's
employees may become  eligible for these  benefits if they reach  retirement age
while working for MEC.  However,  MEC retains the right to change these benefits
anytime at its


                                      -87-
<PAGE>


discretion.  MEC 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
MEC,  MidAmerican  Capital and Midwest  Capital.  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 and
is reflected in the Benefit Obligation of MEC as of December 31, 1999.

MEC  also  maintains   noncontributory,   nonqualified   supplemental  executive
retirement plans for active and retired participants.

Net periodic pension,  supplemental  retirement and postretirement benefit costs
included the following  components for the Company for the period from March 12,
1999 through December 31, 1999 (in thousands):

                                         Pension Cost     Postretirement Cost
                                         ------------     -------------------

Service cost..........................     $  9,854            $ 2,478
Interest cost.........................       25,505              6,423
Expected return on plan assets........      (37,392)            (3,540)
Curtailment loss......................        4,270                  -
                                           --------            -------
  Net periodic pension cost (benefit).     $  2,237            $ 5,361
                                           ========            =======

The pension plan assets are in external  trusts and are  comprised of corporate,
domestic and  international  equity  securities,  United States government debt,
corporate  bonds,  real estate,  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,  1999,  MEC has  Rabbi  trusts  which  hold  corporate-owned  life
insurance 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 life insurance policies was $64.8 million
at December 31, 1999.

During 1999 certain  participants in the supplemental  executive retirement plan
left MEC 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 the period
from  March 12,  1999  through  December  31,  1999.  Additionally,  termination
benefits provided to the participants,  totaling $3.5 million,  were expensed by
MEC during the year ended December 31, 1999.

The projected  benefit  obligation and  accumulated  benefit  obligation for the
supplemental  executive  retirement  plans were $68.8 million and $65.5 million,
respectively, as of December 31, 1999.

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, 1999 (dollars in thousands):


                                      -88-
<PAGE>

                                                    Pension    Postretirement
                                                    Benefits      Benefits
                                                   ---------   --------------
Reconciliation of benefit obligation:
Benefit obligation at beginning of year ........   $ 456,475    $ 120,188
Service cost ...................................      12,192        3,066
Interest cost ..................................      31,556        7,947
Participant contributions ......................         107        1,838
Plan amendments ................................      14,823        2,775
Actuarial gain .................................     (41,567)     (18,248)
Curtailment ....................................        (705)          --
Termination benefits ...........................       3,471           --
Benefits paid ..................................     (29,182)      (9,822)
                                                   ---------    ---------
    Benefit obligation at end of year ..........     447,170      107,744
                                                   ---------    ---------

Reconciliation of the fair value of plan assets:

Fair value of plan assets at beginning of year .     524,508       63,093
Employer contributions .........................       4,201       12,405
Participant contributions ......................         107        1,838
Actual return on plan assets ...................     105,425        5,108
Benefits paid ..................................     (29,182)      (9,822)
                                                   ---------    ---------
    Fair value of plan assets at end of year ...     605,059       72,622
                                                   ---------    ---------

Funded status ..................................     157,889      (35,122)
Unrecognized net gain ..........................    (101,434)     (18,943)
Unrecognized prior service cost ................       9,540        2,776
                                                   ---------    ---------
    Net amount recognized in the consolidated
      balance sheet ............................   $  65,995    $ (51,289)
                                                   =========    =========

                                                   Pension    Postretirement
                                                   Benefits      Benefits
                                                   ---------  --------------
Amounts recognized in the consolidated balance
  sheet consist of:
Prepaid benefit cost .........................     $ 108,907    $   1,042
Accrued benefit liability ....................       (65,533)     (52,331)
Intangible asset .............................        22,621           --
                                                   ---------    ---------
    Net amount recognized ....................     $  65,995    $ (51,289)
                                                   =========    =========


                                             Pension and Postretirement
                                                    Assumptions
                                             --------------------------
Assumptions used were:
Discount rate................................         7.75%
Rate of increase in compensation levels......         5.00%
Weighted average expected long-term
    rate of return on assets.................         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 7.5%
in 2000 and that the rate of increase  thereafter  will decline by .75% annually
to an ultimate rate of 5.25% by the year 2003.  For covered  individuals  age 65
and older, it is assumed health care costs will increase by 5.5% annually.


                                      -89-
<PAGE>


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 1999 would  increase by $2.0 million,  and the  postretirement
benefit obligation at December 31, 1999, would increase by $15.2 million. If the
assumed  health care trend rates were to decrease by 1.0%, the total service and
interest  cost for 1999 would  decrease by $1.6  million and the  postretirement
benefit obligation at December 31, 1999, would decrease by $12.1 million.

18.  COMMITMENTS AND CONTINGENCIES

DECOMMISSIONING COSTS

Based on  site-specific  decommissioning  studies that include  decontamination,
dismantling, site restoration and dry fuel storage cost, MEC's share of expected
decommissioning  costs for Cooper and Quad Cities Station,  in 1999 dollars,  is
$267   million   and  $255   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.

As of December 31, 1999,  MEC's share of funds set aside by NPPD in internal and
external  accounts for  decommissioning  was $109.8  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 after the bonds are retired in early 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.  MEC makes  payments  to NPPD
related to decommissioning Cooper. The Cooper decommissioning component of MEC's
payments to NPPD was $9.1  million,  for the period from March 12, 1999  through
December  31, 1999 and is  included in  operating  expenses.  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, 1999, was $141.6 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.

MEC's provision for depreciation  included costs for Quad Cities Station nuclear
decommissioning  of $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 MEC's
Illinois and Iowa tariffs  assumes  decommissioning  costs,  related to the Quad
Cities  Station,  will escalate at an annual rate of 5.0% 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 $1.6  million  for the period  from March 12, 1999
through December 31, 1999.

NUCLEAR INSURANCE

MEC 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 ComEd (the joint
owner and operator of Quad Cities Station), insurance purchased directly by MEC,
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.


                                      -90-
<PAGE>


The NPPD and ComEd 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, MEC's aggregate maximum potential share
of an assessment  for Cooper and Quad Cities  Station  combined is $88.1 million
per incident, payable in installments not to exceed $10 million annually.

The  property   coverage   provides  for  property  damage,   stabilization  and
decontamination  of the facility,  disposal of the  decontaminated  material and
premature decommissioning.  For Quad Cities Station, ComEd purchases primary and
excess property insurance  protection for the combined interests in Quad Cities,
with  coverage  limits  totaling  $2.1  billion.  For  Cooper,  MEC 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 MEC and the NPPD are covered for their  respective
50%  obligation  in the event of a loss totaling up to $2.75  billion.  MEC 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 MEC, and the property  coverages  purchased by ComEd, which includes
the interests of MEC, 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 MEC from industry  mutual
policies  for its  obligations  associated  with Cooper and Quad Cities  Station
combined, total $11.6 million.

The master nuclear worker liability coverage, which is purchased by the NPPD and
ComEd 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.


                                      -91-
<PAGE>
19.  SEGMENT INFORMATION:

The Company has identified four reportable  business segments  principally based
on  geographic  area:  Domestic  electricity  generation,   foreign  electricity
generation (primarily the Philippines),  domestic utility operations and foreign
utility operations  (primarily the United Kingdom).  Information  related to the
Company's reportable operating segments are shown below (in thousands).

                                      Year Ended December 31,
                               ---------------------------------------
                                  1999         1998           1997
                               ----------   -----------    -----------
REVENUE:
Domestic generation ........   $  106,894   $   583,311    $   570,587
Foreign generation .........      210,366       223,650        102,960
Domestic utility ...........    1,811,599            --             --
Foreign utility ............    2,098,976     1,842,930      1,566,442
                               ----------   -----------    -----------
Segment revenue ............    4,227,835     2,649,891      2,239,989
Corporate ..................      170,948        32,820         30,922
                               ----------   -----------    -----------
                               $4,398,783   $ 2,682,711    $ 2,270,911
                               ==========   ===========    ===========
OPERATING INCOME: (1)
Domestic generation ........   $   67,936   $   313,983    $   301,589
Foreign generation .........      126,245       142,977         61,131
Domestic utility ...........      271,442            --             --
Foreign utility ............      201,203       172,772        191,299
                               ----------   -----------    -----------
Segment operating income ...      666,826       629,732        554,019
Corporate ..................      116,416       (10,387)       (12,882)
                               ----------   -----------    -----------
                               $  783,242   $   619,345    $   541,137
                               ==========   ===========    ===========
CAPITAL EXPENDITURES:
Domestic generation ........   $  145,255   $   105,458    $    58,956
Foreign generation .........       95,552       204,301        177,813
Domestic utility ...........      203,359            --             --
Foreign utility (2) ........      202,073       184,631        134,050
                               ----------   -----------    -----------
Segment capital expenditures      646,239       494,390        370,819
Corporate ..................          120           537          9,830
                               ----------   -----------    -----------
                               $  646,359   $   494,927    $   380,649
                               ==========   ===========    ===========

(1) Operating income excludes  interest  expense,  net of capitalized  interest.
1997 excludes the losses on non-recurring items of $87.0 million and the loss on
equity investment in Casecnan

(2) Capital  expenditures  at the foreign utility exclude the effect of exchange
rate changes.


                                     -92-
<PAGE>


                                  As of December 31,
                              ------------------------
                                 1999          1998
                              -----------   ----------
IDENTIFIABLE ASSETS:
Domestic generation .......   $   858,812   $2,458,842
Foreign generation ........     1,259,463    1,956,387
Domestic utility ..........     5,192,448           --
Foreign utility ...........     2,972,705    3,095,839
                              -----------   ----------
Segment identifiable assets    10,283,428    7,511,068
Corporate .................       482,924    1,592,456
                              -----------   ----------
                              $10,766,352   $9,103,524
                              ===========   ==========

LONG-LIVED ASSETS:
Domestic generation .......   $   595,607   $1,960,433
Foreign generation ........       996,764    1,275,104
Domestic utility ..........     4,166,595           --
Foreign utility ...........     2,438,877    2,519,615
                              -----------   ----------
Segment long-lived assets .     8,197,843    5,755,152
Corporate .................        20,991       19,063
                              -----------   ----------
                              $ 8,218,834   $5,774,215
                              ===========   ==========

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 as well as the
non-recurring  gains on the sales of the qualified  facilities and McLeod common
stock,  the  gain  on  the  Indonesia   insurance  proceeds  and  the  Berkshire
transaction costs.

                                     -93-
<PAGE>

20.  QUARTERLY FINANCIAL DATA (UNAUDITED)

Following is a summary of the Company's  quarterly results of operations for the
years ended December 31, 1999 and 1998 (in thousands, except per share amounts):

<TABLE>
<CAPTION>

                                                                           THREE MONTHS ENDED *
1999:                                                      MARCH 31      JUNE 30     SEPTEMBER 30    DECEMBER 31
                                                          ---------    -----------   ------------    -----------

<S>                                                       <C>          <C>            <C>            <C>
Operating revenue .....................................   $ 797,885    $ 1,003,602    $ 1,062,560    $ 1,264,690
Total revenue .........................................     858,018      1,115,442      1,089,917      1,335,406
Total costs and expenses ..............................     781,259      1,004,713      1,000,545      1,255,197
                                                          ---------    -----------    -----------    -----------
Income before income taxes ............................      76,759        110,729         89,372         80,209
Provision for income taxes ............................      26,065         37,227         27,491          2,692
                                                          ---------    -----------    -----------    -----------
Income before minority interest .......................      50,694         73,502         61,881         77,517
Minority interest .....................................      10,903         12,441         12,185         11,394
                                                          ---------    -----------    -----------    -----------
Income before extraordinary item ......................      39,791         61,061         49,696         66,123
Extraordinary item, net of tax ........................     (31,520)        (5,366)        (3,170)        (9,385)
                                                          ---------    -----------    -----------    -----------
Net income attributable to common stockholders ........   $   8,271    $    55,695    $    46,526    $    56,738
                                                          =========    ===========    ===========    ===========

Income per share before extraordinary item ............   $     .67    $      1.02    $       .82    $      1.11
Extraordinary item ....................................        (.53)          (.09)          (.05)          (.16)
                                                          ---------    -----------    -----------    -----------
Net income per share ..................................   $     .14    $       .93    $       .77    $       .95
                                                          =========    ===========    ===========    ===========
Weighted average basic shares outstanding .............      59,205         60,037         60,592         59,880
                                                          =========    ===========    ===========    ===========

Income per share before extraordinary item diluted ....   $     .62    $       .91    $       .75    $      1.00
Extraordinary item - diluted ..........................        (.43)          (.08)          (.05)          (.13)
                                                          ---------    -----------    -----------    -----------
Net income per share - diluted ........................   $     .19    $       .83    $       .70    $       .87
                                                          =========    ===========    ===========    ===========
Weighted average diluted shares outstanding ...........      73,244         72,638         71,330         70,615
                                                          =========    ===========    ===========    ===========
</TABLE>
                                      -94-
<PAGE>

<TABLE>
<CAPTION>

                                                                       THREE MONTHS ENDED *
1998:                                                      MARCH 31      JUNE 30      SEPTEMBER 30   DECEMBER 31
                                                          ---------    -----------    ------------   -----------
<S>                                                       <C>          <C>            <C>            <C>
Operating revenue .....................................   $ 621,851    $   590,589    $   600,862    $   741,904
Total revenue .........................................     644,311        620,518        627,747        790,135
Total costs and expenses ..............................     588,401        555,961        537,477        728,819
                                                          ---------    -----------    -----------    -----------
Income before income taxes ............................      55,910         64,557         90,270         61,316
Provision for income taxes ............................      18,531         21,952         32,112         20,670
                                                          ---------    -----------    -----------    -----------
Income before minority interest .......................      37,379         42,605         58,158         40,646
Minority interest .....................................      10,084         10,139         10,535         10,518
                                                          ---------    -----------    -----------    -----------
Income before extraordinary item and cumulative
   effect of change in accounting principle ...........      27,295         32,466         47,623         30,128
Extraordinary item, net of tax ........................          --             --             --         (7,146)
Cumulative effect of change in accounting
   principle, net of tax ..............................          --             --             --         (3,363)
                                                          ---------    -----------    -----------    -----------
Net income attributable to common stockholders ........   $  27,295    $    32,466    $    47,623    $    19,619
                                                          =========    ===========    ===========    ===========

Income per share before extraordinary item and
   cumulative effect of change in accounting principal          .45    $       .54    $       .80    $       .51
Extraordinary item ....................................          --             --             --           (.12)
Cumulative effect of change in accounting principle ...          --             --             --           (.06)
                                                          ---------    -----------    -----------    -----------
Net income per share ..................................         .45    $       .54    $       .80    $       .33
                                                          =========    ===========    ===========    ===========
Weighted average basic shares outstanding .............      61,081         60,235         59,674         59,566
                                                          =========    ===========    ===========    ===========

Income per share before extraordinary item and
   cumulative effect of change in accounting
   principle - diluted ................................         .43    $       .51    $       .72    $       .48
Extraordinary item - diluted ..........................          --             --             --           (.10)
Cumulative effect of change in accounting
   principle - diluted ................................          --             --             --           (.04)
                                                          ---------    -----------    -----------    -----------
Net income per share - diluted ........................         .43    $       .51    $       .72    $       .34
                                                          =========    ===========    ===========    ===========
Weighted average diluted shares outstanding ...........      69,343         74,346         73,540         73,627
                                                          =========    ===========    ===========    ===========
</TABLE>

* The Company's operations are seasonal in nature.


                                      -95-
<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 and subsidiaries (the "Company") as of December 31, 1999
and 1998, and the related consolidated  statements of operations,  stockholders'
equity,  and cash flows for each of the three years in the period ended December
31, 1999. Our audit 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 the financial  statements and financial statement schedule
based on our audits.

We  conducted  our  audits  in  accordance  with  generally   accepted  auditing
standards.  Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement.  An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements.  An audit also includes
assessing the  accounting  principles  used and  significant  estimates  made by
management,  as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion,  such consolidated  financial  statements present fairly, in all
material respects, the financial position of MidAmerican Energy Holdings Company
and  subsidiaries  as of December  31,  1999 and 1998,  and the results of their
operations  and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting  principles.
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 25, 2000
(March 14, 2000 as to Note 3)



                                      -96-
<PAGE>


MIDAMERICAN ENERGY HOLDINGS COMPANY                                 SCHEDULE I
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
as of December 31, 1999 and 1998
(dollars in thousands)

<TABLE>
<CAPTION>

                                                                       1999           1998
                                                                    -----------    -----------
<S>                                                                 <C>            <C>
ASSETS
Current Assets:
   Cash and cash equivalents ....................................   $   240,938    $ 1,522,294
                                                                    -----------    -----------
     Total current assets .......................................       240,938      1,522,294

   Investments in and advances to subsidiaries and joint ventures     2,972,843      2,430,734
   Equipment, net ...............................................        16,728         17,554
   Deferred charges and other assets ............................       158,887        155,332
                                                                    -----------    -----------

     Total assets ...............................................   $ 3,389,396    $ 4,125,914
                                                                    ===========    ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
   Accounts payable and other accrued liabilities ...............   $    88,490    $    98,940
                                                                    -----------    -----------
     Total current liabilities ..................................        88,490         98,940

Parent company debt .............................................     1,856,318      2,645,991
                                                                    -----------    -----------

   Total liabilities ............................................     1,944,808      2,744,931
                                                                    -----------    -----------

Company-obligated mandatorily redeemable
   convertible preferred securities of subsidiary trusts ........       450,000        553,930

Stockholders' equity:
   Preferred stock - authorized 2,000 shares, no par value ......            --             --
   Common stock -authorized 180,000 shares, no par value
     issued 82,980 shares, 59,944 and 59,605 shares, respectively            --             --
   Additional paid in capital ...................................     1,249,079      1,238,690
   Retained earnings ............................................       507,726        340,496
   Accumulated other comprehensive income .......................       (12,029)            45
   Treasury stock - 23,036 and 23,375 common shares,
     respectively, at cost ......................................      (750,188)      (752,178)
                                                                    -----------    -----------
   Total stockholders' equity ...................................       994,588        827,053
                                                                    -----------    -----------
   Total liabilities and stockholders' equity ...................   $ 3,389,396    $ 4,125,914
                                                                    ===========    ===========

</TABLE>

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


                                      -97-
<PAGE>


MIDAMERICAN  ENERGY HOLDINGS  COMPANY                                SCHEDULE I
PARENT COMPANY ONLY (CONTINUED)
CONDENSED  STATEMENTS OF OPERATIONS
for the three years ended December 31, 1999
(dollars and shares in thousands, except per share amounts)

<TABLE>
<CAPTION>

                                                                    1999         1998         1997
                                                                  ---------    ---------    ----------
<S>                                                               <C>          <C>          <C>
Revenue:

Equity in undistributed earnings of subsidiary companies
   and joint ventures .........................................   $ 159,439    $ 205,049    $  79,905
Cash dividends and distributions from subsidiary
   companies and joint ventures ...............................     345,430      179,782      156,686
Interest and other income .....................................      34,002       44,686       49,488
                                                                  ---------    ---------    ---------

   Total revenues .............................................     538,871      429,517      286,079
                                                                  ---------    ---------    ---------

Expenses:

General and administration ....................................      40,262       30,527       36,616
Interest, net of capitalized interest .........................     156,600      132,250       75,438
                                                                  ---------    ---------    ---------

   Total expenses .............................................     196,862      162,777      112,054
                                                                  ---------    ---------    ---------

Income before provision for income taxes ......................     342,009      266,740      174,025
Provision for income taxes ....................................      93,475       93,265       99,044
                                                                  ---------    ---------    ---------

Income before minority interest ...............................     248,534      173,475       74,981
Minority interest .............................................      31,863       35,963       23,158
                                                                  ---------    ---------    ---------

Income before extraordinary items and cumulative effect of
   change in accounting principle .............................     216,671      137,512       51,823
Extraordinary items, net of tax ...............................     (49,441)      (7,146)    (135,850)
Cumulative effect of change in accounting principle, net of tax          --       (3,363)          --
                                                                  ---------    ---------    ---------
Net income (loss) available to common stockholders ............   $ 167,230    $ 127,003    $ (84,027)
                                                                  =========    =========    =========

Income per share before extraordinary items and cumulative
   effect of change in accounting principle ...................   $    3.62    $    2.29    $     .77
Extraordinary items ...........................................        (.83)        (.12)       (2.02)
Cumulative effect of change in accounting principle ...........          --         (.06)          --
                                                                  ---------    ---------    ---------
Net income (loss) per share ...................................   $    2.79    $    2.11    $   (1.25)
                                                                  =========    =========    =========

Income per share before extraordinary items and cumulative
   effect of change in accounting principle - diluted .........   $    3.28    $    2.15    $     .75
Extraordinary items - diluted .................................        (.69)        (.10)       (1.97)
Cumulative effect of change in accounting principle - diluted .          --         (.04)          --
                                                                  ---------    ---------    ---------
Net income (loss) per share - diluted .........................   $    2.59    $    2.01    $   (1.22)
                                                                  =========    =========    =========

Average number of shares outstanding ..........................      59,929       60,139       67,268
                                                                  =========    =========    =========
Diluted shares ................................................      71,948       74,100       68,686
                                                                  =========    =========    =========

</TABLE>

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


                                      -98-
<PAGE>


MIDAMERICAN ENERGY HOLDINGS COMPANY                                  SCHEDULE I
PARENT COMPANY ONLY (continued)
CONDENSED  STATEMENTS OF CASH FLOWS
for the three years ended  December 31, 1999
(dollars in thousands)

<TABLE>
<CAPTION>

                                                           1999           1998           1997
                                                        -----------    -----------    -----------
<S>                                                     <C>            <C>            <C>
Cash flows from operating activities ................   $  (261,276)   $  (219,705)   $  (200,057)
                                                        -----------    -----------    -----------

Cash flows from investing activities:
Decrease (increase) in advances to and investments in
   subsidiaries and joint ventures ..................       (53,215)      (103,494)       174,584
Decrease (increase) in short-term investments .......            --            421           (229)
Other ...............................................        (4,390)       (24,749)        18,330
                                                        -----------    -----------    -----------

Cash flows from investing activities ................       (57,605)      (127,822)       192,685
                                                        -----------    -----------    -----------

Cash flows from financing activities:
Proceeds from sale of common and treasury stock
   and exercise of stock options ....................         5,482          3,412        703,624
Proceeds from issuance of parent company debt .......            --      1,502,243        350,000
Proceeds from convertible preferred securities
   of subsidiary trusts .............................            --             --        450,000
Repayment of parent company debt ....................      (853,420)      (167,285)      (100,000)
Net proceeds from revolver ..........................            --             --        (95,000)
Purchase of treasury stock ..........................      (104,847)      (724,791)       (55,505)
Deferred charges relating to debt financing .........        (9,690)       (24,235)       (33,719)
                                                        -----------    -----------    -----------

Cash flows from financing activities ................      (962,475)       589,344      1,219,400
                                                        -----------    -----------    -----------

Net increase (decrease) in cash and cash equivalents     (1,281,356)       241,817      1,212,028

Cash and cash equivalents at beginning of period ....     1,522,294      1,280,477         68,449
                                                        -----------    -----------    -----------

Cash and cash equivalents at end of period ..........   $   240,938    $ 1,522,294    $ 1,280,477
                                                        ===========    ===========    ===========
Supplemental disclosures:
Interest paid (net of amount capitalized) ...........   $   173,285    $   104,350    $    38,176
                                                        ===========    ===========    ===========

Income taxes paid ...................................   $    83,280    $    32,100    $    35,302
                                                        ===========    ===========    ===========
</TABLE>

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


                                      -99-
<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, 2000.

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, 2000
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and
Director

/s/  Gregory E. Abel*                                   March 30, 2000
Gregory E. Abel
President, Chief Operating Officer and Director


/s/  Patrick J. Goodman*                                March 30, 2000
Patrick J. Goodman
Senior Vice President and
Chief Financial Officer


/s/  Edgar D. Aronson*                                  March 30, 2000
Edgar D. Aronson
Director


/s/  Stanley J. Bright *                                March 30, 2000
Stanley J. Bright
Director


/s/  Walter Scott, Jr.*                                 March 30, 2000
Walter Scott, Jr.
Director

                                      -100-
<PAGE>

/s/  Marc D. Hamburg *                                  March 30, 2000
Marc D. Hamburg
Director


/s/  Warren Buffett*                                    March 30, 2000
Warren Buffett
Director


/s/  John Boyer*                                        March 30, 2000
John Boyer
Director


/s/  W. David Scott*                                    March 30, 2000
W. David Scott
Director


*By:/s/  Steven A. McArthur                             March 30, 2000
Steven A. McArthur
Attorney-in-Fact



                                     -101-
<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 refer-
          ence 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 an
          Steven A. McArthur, dated May 10, 1999.

                                     -102-
<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  Agreemen
          dated February 18, 1994 and the Fourth  Amendment to 25 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 (incor-
          porated 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 SavingsAssocia-
          tion 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 Geotherma
          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 Geo-
          thermal Power Company,  Inc. and Overseas Private Investment  Corpora-
          tion  (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 Geo-
          thermal  Power  Company,  Inc. (incorporated  by  reference to Exhibit
          10.104 to the Company's 1994 Form 10-K).

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).

                                     -103-
<PAGE>

10.20     231 MW Power Plant - Malitbog  Agreement  ("Malitbog  ECA") dated Sep-
          tember 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 Ban
          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 Geo-
          thermal  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. (incor-
          porated 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 refer-
          ence 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 th
          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


                                     -104-
<PAGE>

          deFrance,  Service  National and Others  (incorporated  by reference
          to Exhibit 10.133 to the Company's 1996 Form 10-K).

10.32     Master  Connection  and User System  Agreement  with The National Grid
          Company plc  (incorporated  by reference to Exhibit 10.134 to the Com-
          pany's 1996 Form 10-K).

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

10.34     Acquisition  Agreement by  and  between  CalEnergy  Company,  Inc. an
          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., MidAmeri-
          can 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,  betwee
          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.)

                                     -105-
<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. (incorpor-
          ated 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.  (inco-
          porated by reference to Iowa-Illinois as Exhibit 4.B.30 to  Commissio
          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.
          (incorporated 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.
          (incorporated  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 Mid-
          American  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, Reg-
          istration 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.)

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.)


                                     -106-
<PAGE>


10.58     MidAmerican  Energy  Company  Severance  Plan  For Specified  Officers
          dated  November 1, 1996.  (incorporated  by reference to Exhibit  10.1
          to  MidAmerican 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
          Compensation 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, Commis-
          sion 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
          Midwest 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 o
          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, Commission 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 10.2
          to MidAmerican Energy's Quarterly Reports on the combined Form 10- 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.

27.0      Financial Data Schedule.

*To be filed by amendment.



                                     -107-