UNITED STATES 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, 2002

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

      Iowa                                                    94-2213782
      ----                                                 -------------
(State or other jurisdiction of                            (I.R.S. Employer
incorporation or organization)                             Identification No.)


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

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

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

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

Indicate by check mark if disclosure of delinquent  filers  pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of each of the  registrants'  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. [ ]

Indicate  by check mark  whether  the  registrant  is an  accelerated  filer (as
defined by Rule 12b-2 of the Act). Yes [ ] No [X]

All of the shares of MidAmerican  Energy Holdings  Company are held by a limited
group of private  investors.  As of March 31, 2003,  9,281,087  shares of common
stock were outstanding.

<PAGE>



                                TABLE OF CONTENTS

                                     PART I

Item 1.    Business..........................................................  3
Item 2.    Properties........................................................ 30
Item 3.    Legal Proceedings................................................. 32
Item 4.    Submission of Matters to a Vote of Security Holders............... 34

                                     PART II

Item 5.    Market for Registrant's Common Equity and Related
             Stockholder Matters............................................. 35
Item 6.    Selected Financial Data........................................... 36
Item 7.    Management's Discussion and Analysis of Financial Condition
             and Results of Operations....................................... 37
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk........ 49
Item 8.    Financial Statements and Supplementary Data....................... 50
Item 9.    Changes in and Disagreements with Accountants on Accounting
             and Financial Disclosure........................................ 96

                                    PART III

Item 10.   Directors and Executive Officers of the Registrant................ 97
Item 11.   Executive Compensation............................................ 99
Item 12.   Security Ownership of Certain Beneficial Owners and
             Management and Related Stockholder Matters......................103
Item 13.   Certain Relationships and Related Transactions....................104
Item 14.   Controls and Procedures...........................................105

                                     PART IV

Item 15.   Exhibits, Financial Statement Schedules and Reports on Form 8-K...106

SIGNATURES ..................................................................111
CERTIFICATIONS...............................................................113
Exhibit Index................................................................115

                                      -2-
<PAGE>
                                     PART I

ITEM 1.  BUSINESS.

GENERAL

MidAmerican  Energy  Holdings  Company and its  subsidiaries  (the  "Company" or
"MEHC") is a United  States-based  privately  owned global energy  company.  The
Company's  subsidiaries' principal businesses are regulated electric and natural
gas utilities,  regulated interstate natural gas transmission and electric power
generation.   Its  operations  are  organized  and  managed  on  seven  distinct
platforms:  MidAmerican Energy Company  ("MidAmerican  Energy"),  Kern River Gas
Transmission  Company ("Kern River"),  Northern  Natural Gas Company  ("Northern
Natural  Gas"),  CE  Electric UK Funding  ("CE  Electric  UK")  (which  includes
Northern  Electric plc  ("Northern  Electric")  and  Yorkshire  Power Group Ltd.
("Yorkshire")),  CalEnergy Generation - Domestic,  CalEnergy  Generation-Foreign
(the Upper Mahiao,  Malitbog and Mahanagdong  Projects  (collectively the "Leyte
Projects")  and  the  Casecnan  Project)  and  HomeServices  of  America,   Inc.
("HomeServices").  Through six of these platforms, the Company owns and operates
a combined  electric and natural gas utility  company in the United States,  two
natural  gas  pipeline   companies  in  the  United  States,   two   electricity
distribution  companies in the United  Kingdom,  and a diversified  portfolio of
domestic and international independent power projects. The Company also owns the
second largest residential real estate brokerage firm in the United States.

The Company's principal subsidiaries generate,  transmit,  store, distribute and
supply  energy.  The  Company's  electric  and natural gas utility  subsidiaries
currently   serve   approximately   4.3  million   electricity   customers   and
approximately   660,000   natural  gas  customers.   Its  natural  gas  pipeline
subsidiaries   operate   interstate   natural  gas  transmission   systems  with
approximately  17,500 miles of pipeline in operation and peak delivery  capacity
of 5.3 Bcf of natural gas per day. The Company has  interests in 6,191 net owned
MW of power generation facilities in operation and construction, including 4,618
net owned MW in facilities  that are part of the regulated  return asset base of
its electric  utility business (as further  described in  "Business--MidAmerican
Energy--Electric  Operations")  and  1,573  net  owned MW in  non-utility  power
generation  facilities.  Substantially  all of the non-utility  power generation
facilities have long-term  contracts for the sale of energy and/or capacity from
the facilities.

On March 14,  2000,  the Company and an investor  group  comprised  of Berkshire
Hathaway  Inc.,  Walter Scott,  Jr., a Director of the Company,  David L. Sokol,
Chairman  and Chief  Executive  Officer  of the  Company,  and  Gregory E. Abel,
President  and Chief  Operating  Officer of the Company,  closed on a definitive
agreement  and plan of merger  whereby the  investor  group  acquired all of the
outstanding common stock of the Company (the "Teton  Transaction").  As a result
of the Teton Transaction,  Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel
own approximately 9.7%, 86%, 3% and 1% of the voting stock respectively.

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
initially  incorporated  in 1971 under the laws of the State of Delaware and was
reincorporated in 1999 in Iowa, at which time it changed its name from CalEnergy
Company, Inc. to MidAmerican Energy Holdings Company.

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

MIDAMERICAN ENERGY

MidAmerican  Energy is the largest energy company  headquartered  in Iowa,  with
$3.8 billion of assets as of December 31,  2002,  and revenue for 2002  totaling
$2.2  billion.  MidAmerican  Energy is  principally  engaged in the  business of
generating,  transmitting,  distributing  and  selling  electric  energy  and in
distributing,   selling  and  transporting   natural  gas.   MidAmerican  Energy
distributes  electricity at retail in Council  Bluffs,  Des Moines,  Fort Dodge,
Iowa  City,  Sioux City and  Waterloo,  Iowa;  the Quad  Cities  (Davenport  and
Bettendorf,  Iowa and Rock  Island,  Moline and East  Moline,  Illinois);  and a
number of adjacent  communities  and areas. It also  distributes  natural gas at
retail in Cedar  Rapids,  Des  Moines,  Fort  Dodge,  Iowa City,  Sioux City and
Waterloo,  Iowa;  the Quad Cities;  Sioux Falls,  South Dakota;  and a number of
adjacent communities and areas. As of December 31, 2002,  MidAmerican Energy had
approximately  681,000 retail electric  customers and 660,000 retail natural gas
customers.

                                      -3-

<PAGE>

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

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

MidAmerican  Energy  has a diverse  customer  base  consisting  of  residential,
agricultural and a variety of commercial and industrial  customer groups.  Among
the primary industries served by MidAmerican Energy are those that are concerned
with food products,  the  manufacturing,  processing and  fabrication of primary
metals, real estate,  farm and other  non-electrical  machinery,  and cement and
gypsum products.

For the year ended December 31, 2002,  MidAmerican Energy derived  approximately
61% of its gross operating revenues from its electric utility business, 31% from
its gas utility business and 8% from its non-regulated business activities.  For
2001 and 2000, the corresponding  percentages were 56% electric,  37% gas and 7%
non-regulated and 53% electric, 41% gas and 6% non-regulated,  respectively. The
change in revenue mix is principally driven by changes in natural gas prices and
seasonality.

There  are  seasonal  variations  in  MidAmerican   Energy's  electric  and  gas
businesses,  which  are  principally  related  to the  use  of  energy  for  air
conditioning and heating. In 2002, 41% of MidAmerican  Energy's electric utility
revenues were reported in the months of June,  July,  August and September,  and
47% of MidAmerican  Energy's gas utility revenues were reported in the months of
January, February, March and December.

Electric Operations

The  electric  utility  industry   continues  to  undergo   regulatory   change.
Traditionally,  prices charged by electric utility companies have been regulated
by federal  and state  commissions  and have been based on cost of  service.  In
recent  years,  changes  have  been  occurring  that move the  electric  utility
industry toward a more  competitive,  market-based  pricing  environment.  These
changes  may  have a  significant  impact  on the way  MidAmerican  Energy  does
business.

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

For the year ended  December 31, 2002,  regulated  electric sales by MidAmerican
Energy by customer class were as follows:  19.8% were to residential  customers,
14.2% were to small  general  service  customers,  24.5%  were to large  general
service customers, 9.1% were to other customers, and 32.4% were wholesale sales.
For the year ended  December 31, 2002,  regulated  electric sales by MidAmerican
Energy by  jurisdiction  were as follows:  88.5% to Iowa,  10.7% to Illinois and
0.8% to South Dakota.

The annual hourly peak demand on  MidAmerican  Energy's  electric  system occurs
principally as a result of air  conditioning  use during the cooling season.  In
July 2002,  MidAmerican Energy recorded an hourly peak demand of 3,889 MW, which
was 56 MW greater than MidAmerican Energy's previous record hourly peak of 3,833
MW set in 1999.

                                      -4-

<PAGE>

The following table sets out certain information concerning MidAmerican Energy's
power generation facilities based upon summer 2002 accreditation:
<TABLE>
<CAPTION>

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

<S>                                              <C>         <C>        <C>          <C>           <C>
COAL FACILITIES:
  Council Bluffs Energy Center Units 1 & 2         133         133       Coal          Iowa        1954, 1958
  Council Bluffs Energy Center Unit 3 ....         690         546       Coal          Iowa              1978
  Louisa Generation Station ..............         700         616       Coal          Iowa              1983
  Neal Generation Station Units 1 & 2 ....         435         435       Coal          Iowa        1964, 1972
  Neal Generation Station Unit 3 .........         515         371       Coal          Iowa              1975
  Neal Generation Station Unit 4 .........         644         261       Coal          Iowa              1979
  Ottumwa Generation Station .............         708         368       Coal          Iowa              1981
  Riverside Generation Station ...........         135         135       Coal          Iowa         1925-61
                                                 -----       -----
    Total coal facilities ................       3,960       2,865
                                                 -----       -----
OTHER FACILITIES:
  Combustion Turbines ....................         785         785      Gas/Oil        Iowa         1969-95
  Moline Water Power .....................           3           3       Hydro       Illinois            1970
  Quad Cities Generating Station .........       1,636         409      Nuclear      Illinois            1974
  Portable Power Modules .................          56          56        Oil          Iowa              2000
                                                 -----       -----
    Total other facilities ...............       2,480       1,253
                                                 -----       -----

ACCREDITED GENERATING CAPACITY ...........       6,440       4,118
Projects Under Construction -
  Greater Des Moines Energy Center .......         500         500        Gas          Iowa         2003-05
                                                 -----       -----
TOTAL POWER GENERATION CAPACITY ..........       6,940       4,618
                                                 =====       =====
</TABLE>

(1)  MidAmerican Energy operates all such power generation facilities other than
     Quad Cities Generating Station and Ottumwa Generation Station.

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

MidAmerican Energy's accredited net generating  capability in the summer of 2002
was 4,724 MW.  Accredited  net  generating  capability  represents the amount of
generation available to meet the requirements on MidAmerican Energy's system and
consists of MidAmerican  Energy-owned  generation of 4,118 MW,  generation under
power purchase  contracts of 630 MW and the net amount of capacity purchases and
sales of (24) MW. The net generating  capability at any time may be less than it
would  otherwise  be due  to  regulatory  restrictions,  fuel  restrictions  and
generating units being  temporarily out of service for inspection,  maintenance,
refueling or modifications.

MidAmerican  Energy plans to develop and  construct  three  electric  generating
projects  in Iowa.  The  projects  would  provide  service to  regulated  retail
electricity  customers and be included in regulated rate base in Iowa,  Illinois
and South  Dakota.  Wholesale  sales may also be made from the  projects  to the
extent the power is not needed for regulated retail service.

The first  project will be a 500-MW  (based on expected  accreditation)  natural
gas-fired,  combined  cycle  plant  with an  estimated  cost  of  $415  million.
MidAmerican  Energy will own 100% of the plant and operate it. The plant will be
operated  in simple  cycle mode  during  2003 and 2004,  resulting  in 310 MW of
accredited  capacity.  The  combined  cycle  operation  will  commence  in 2005.
MidAmerican  Energy has received a  certificate  from the Iowa  Utilities  Board
"(IUB") allowing it to construct the plant. In May 2002, the IUB issued an order
that specified the Iowa ratemaking  principles that will apply to the plant over
its life. As a result of that order,  MidAmerican  Energy is proceeding with the
construction of the plant.

                                      -5-
<PAGE>

The second project is currently under development and is expected to be a 790-MW
(based on expected accreditation)  super-critical-temperature,  coal-fired plant
fueled with low-sulfur coal. If constructed, MidAmerican Energy will operate the
plant  and  expects  to  own  approximately  475  MW of  the  plant.  Municipal,
cooperative  and  public  power  utilities  will own the  remainder,  which is a
typical ownership arrangement for large base-load plants in Iowa. On January 23,
2003,  MidAmerican  Energy  received  an  order  approving  the  issuance  of  a
certificate from the IUB allowing it to construct the plant.  MidAmerican Energy
has made a filing with the IUB for approval of Iowa  ratemaking  principles  for
this  second  plant.  The  development  of this plant is  subject  to  obtaining
environmental  and other required  permits,  as well as to receiving orders from
the IUB approving  construction  of the associated  transmission  facilities and
establishing ratemaking principles which are satisfactory to MidAmerican Energy.

The third  project is  currently  under  development  and is expected to be wind
power facilities totaling 310 MW (nameplate rating). If constructed, MidAmerican
Energy  will own and  operate  these  facilities,  which  are  expected  to cost
approximately $323 million, plus associated transmission facilities. MidAmerican
Energy's plan to construct the wind project is in conjunction  with a settlement
proposal to extend  through  December  31, 2010, a rate freeze that is currently
scheduled  to  expire  at the end of  2005.  The  proposed  settlement  requires
enactment of Iowa legislation and is subject to approval by the IUB.

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

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

Each MAPP  participant  is  required to maintain  for  emergency  purposes a net
generating capability reserve of at least 15% above its system peak demand. If a
participant's  capability  reserve  falls  below  the 15%  minimum,  significant
penalties could be contractually  imposed by MAPP.  MidAmerican Energy's reserve
margin at peak demand for 2002 was approximately 21%.

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

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

On July 31, 2002, the FERC issued a notice of proposed  rulemaking  with respect
to Standard Market Design. The FERC has characterized the proposal as portending
"sweeping  changes" to the use and expansion of the interstate  transmission and
wholesale  bulk power  systems  in the  United  States.  The  proposal  includes
numerous  proposed  changes  in  the  current  regulation  of  transmission  and
generation  facilities designed "to promote economic efficiency" and replace the
"obsolete patchwork we have today," according to the FERC's chairman.  The final
rule,  if adopted as  currently  proposed,  would  require all public  utilities
operating  transmission  facilities  subject  to the FERC  jurisdiction  to file
revised open access transmission tariffs that would require changes to the basic
services these public utilities currently provide.  The

                                      -6-
<PAGE>

proposed rule may impact the pricing of  MidAmerican  Energy's  electricity  and
transmission  products.  The FERC does not  envision  that a final  rule will be
fully  implemented  until  2004.  MidAmerican  Energy  is still  evaluating  the
proposed rule and  recognizes  the final rule could vary  considerably  from the
initial  proposal.  Accordingly,  the  likely  impact  of the  proposed  rule on
MidAmerican Energy's transmission and generation businesses is unknown.

Gas Operations
--------------

For the year ended December 31, 2002, regulated gas sales by MidAmerican Energy,
excluding  transportation  throughput,  by customer class were as follows: 39.0%
were to residential  customers,  19.7% were to small general service  customers,
1.5% were to large general service customers,  1.2% were to other customers, and
38.6% were wholesale sales. For the year ended December 31, 2002,  regulated gas
sales  by  MidAmerican   Energy,   excluding   transportation   throughput,   by
jurisdiction  were as follows:  78.0% to Iowa,  11.2% to South Dakota,  10.0% to
Illinois, and 0.8% to Nebraska.

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

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

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

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

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

                                      -7-

<PAGE>

KERN RIVER

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

Kern River's 2003 Expansion Project
-----------------------------------

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

The 2003 Expansion  Project  includes the  construction  of three new compressor
stations and the installation of additional  compression and other modifications
at six existing  facilities.  When completed,  the Kern River system will have a
summer day design  capacity  of  approximately  1.73 Bcf per day, an increase of
approximately 886 mmcf per day.

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

The 2003 Expansion Project is being financed with approximately 70% debt and 30%
equity, consistent with Kern River's original capital structure, the application
for FERC approval of the 2003 Expansion Project and the limitations contained in
the indenture for Kern River's  existing secured senior notes. On June 21, 2002,
Kern River entered into an $875 million credit facility to fund a portion of the
costs  of the  2003  Expansion  Project  and the  Company  issued  a  completion
guarantee in favor of the lenders under that credit facility.

NORTHERN NATURAL GAS

Northern  Natural Gas is one of the  largest  interstate  natural  gas  pipeline
systems  in the  United  States.  It  reaches  from  Texas to  Michigan's  Upper
Peninsula  and is engaged in the  transmission  and  storage of natural  gas for
utilities,  municipalities,  other pipeline companies, gas marketers, industrial
and  commercial  users  and other  end  users.  Northern  Natural  Gas  operates
approximately  16,600 miles of natural gas pipelines  with a design  capacity of
4.4 Bcf per day  that  deliver  approximately  5.0%  of the  total  natural  gas
consumed in the United States. The Northern Natural Gas system is believed to be
the largest in the United  States as  measured by pipeline  miles and the eighth
largest  as  measured  by  throughput.  The  pipeline  system is  powered  by 92
transmission  compressor  stations  with an aggregate of  approximately  840,000
horsepower.  Northern  Natural  Gas' storage  services are provided  through the
operation of three  underground  storage  fields (one in Iowa and two in Kansas)
and two LNG storage  peaking units.  The three  underground  natural gas storage
facilities and Northern  Natural Gas' two LNG storage peaking units have a total
storage  capacity of  approximately  59 Bcf and over 1.3 Bcf per day of peak day
deliverability.  These  storage  facilities  provide  Northern  Natural Gas with
operational flexibility for daily balancing of its system and providing services
to customers  for meeting  their  year-round  loadswing  requirements.  In 2002,
approximately  11% of Northern  Natural Gas' revenue was generated  from storage
services.

Northern Natural Gas' system is comprised of two distinct areas, its traditional
end-use  and  distribution  market  area  at the

                                      -8-
<PAGE>

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

The northern portion of Northern Natural Gas' pipeline system transports natural
gas  primarily  to end-user  and local  distributor  markets in the Market Area.
Customers  consist  of  LDCs,  municipalities,  other  pipeline  companies,  gas
marketers  and  end-users.  While  approximately  ten large LDCs account for the
majority of Market Area volumes, Northern Natural Gas also serves numerous small
communities  through these large LDCs as well as  municipalities or smaller LDCs
and directly  serves  several large  end-users.  In 2002,  approximately  85% of
Northern   Natural  Gas'   revenue  was  from   capacity   charges   under  firm
transportation  and storage  contracts and approximately 82% of that revenue was
from LDCs.  In 2002,  approximately  68% of Northern  Natural  Gas'  revenue was
generated from Market Area customer contracts.

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

In the Field Area,  customers holding  transportation  capacity consist of LDCs,
marketers, producers, and end-users. The majority of Northern Natural Gas' Field
Area firm  transportation  is provided to Northern Natural Gas' Market Area firm
customers  under  long-term  firm  transportation  contracts  with such  volumes
supplemented  by volumes  transported on an  interruptible  basis or pursuant to
short-term firm contracts.  In 2002,  approximately 21% of Northern Natural Gas'
revenue was generated from Field Area customer transportation contracts.

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

Northern Natural Gas' revenue is derived from the interstate  transportation and
storage of natural gas for third parties. Except for small quantities of natural
gas owned for system  operations,  Northern Natural Gas does not own the natural
gas that is transported through its system. Northern Natural Gas' transportation
and storage  operations are subject to a FERC-regulated  tariff that is designed
to allow it an opportunity to recover its costs together with a regulated return
on equity.

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

                                      -9-
<PAGE>

KERN RIVER AND NORTHERN NATURAL GAS COMPETITION

Natural gas competes with other forms of energy, including electricity, coal and
fuel  oil,  primarily  on the  basis  of  price.  Legislation  and  governmental
regulations,  the  weather,  the futures  market,  production  costs,  and other
factors beyond the control of Kern River and Northern  Natural Gas influence the
price of natural gas. Industrial end-users often have the ability to choose from
alternative fuel sources in addition to natural gas, such as fuel oil and coal.

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

Approximately  100% of Kern River's original  pipeline capacity is contractually
committed with 14 extended term rate shippers until  September 30, 2011.  Beyond
that,  approximately  86% of the  original  pipeline  capacity is  contractually
committed,  with 11  shippers,  until  September  30,  2016.  Nearly 100% of the
additional  permanent capacity constructed in connection with the 2002 expansion
and to be constructed for the 2003 Expansion Project is contractually  committed
under 10- and 15-year agreements.

Even though Kern River does not market  natural gas supply,  in each market area
the  purchaser  evaluates  the  total  cost of  natural  gas  supply,  including
transportation  rates,  from  each  alternative  supplier/transporter.  Based on
published rates and fuel percentages,  the Company believes Kern River currently
has  the  lowest  transportation  costs  from  well-head  to  burner  tip of any
interstate   pipeline   serving  its  direct  markets  in  Nevada  and  southern
California,  with gas  transportation  costs of  approximately  $0.45  per MMBtu
compared to approximately  $0.84-$1.29 per MMBtu on competing  pipelines.  There
can be no assurance  that its  competitors  do not or will not charge rates that
are discounted to these published rates, particularly on a short-term basis. The
2003  Expansion  Project  shippers'  initial  tariff rates in the original  FERC
filing  were  $0.57-$0.70  per MMBtu.  These  rates are  expected  to be reduced
slightly  in a FERC  compliance  filing  Kern River is  required to make 60 days
prior to placing the 2003 Expansion Project in service.

Kern River is the only interstate  pipeline that presently  delivers natural gas
directly from a gas supply basin into the intrastate  California  market,  which
enables  its  customers  to  avoid  paying  a  "rate  stack"  (i.e.,  additional
transportation  costs  attributable  to the movement from one or more interstate
pipeline  systems  to an  intrastate  system  within  California).  The  Company
believes   that  Kern   River's   rate   structure   and   access  to   upstream
pipelines/storage  facilities  and  to  low-cost  Rocky  Mountain  gas  reserves
increases  its  competitiveness  and  attractiveness  to  end-users.  Kern River
believes it is  advantaged  relative  to other  competing  interstate  pipelines
because its  relatively  new  pipeline can be expanded at lower costs than those
that apply to other systems and it directly links the market along its system to
low cost Rocky Mountain gas supplies. Kern River's strategic advantages were the
main reasons the electric generation market purposely selected sites next to the
Kern River  pipeline  to build  their new power  plants.  Kern River  expects to
directly  serve  over  7,000  MW's of new  electric  generation  load,  which is
currently under construction or recently placed in commercial  operation.  Close
to 90% of the 2003 Expansion Project contract demand is with shippers who either
own or intend to serve power generation facilities.

Historically,  Northern  Natural Gas has been able to provide  competitive  cost
service  because of its access to a variety of low cost supply basins,  its cost
control measures and its relatively high load factor  through-put,  which lowers
the  cost  per  unit  of  transportation.  Although  Northern  Natural  Gas  has
experienced  pipeline system bypass  affecting a small percentage of its market,
to date Northern  Natural Gas has been able to more than offset any load lost to
bypass in the Market Area through  expansion  projects such as the Peak Day 2000
project.

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

Northern  Natural  Gas  believes  that  current and  anticipated  changes in its
competitive  environment have created

                                      -10-
<PAGE>

opportunities  to serve existing  customers more efficiently and to meet certain
growing  supply  needs.  While LDCs provide peak day delivery  growth  driven by
population growth and alternative fuel  replacement,  new off-peak demand growth
is being driven primarily by power and ethanol plant expansion.  Off-peak demand
growth is  important  to Northern  Natural Gas as this demand can  generally  be
satisfied with little or no requirement for the  construction of new facilities.
Approximately 3,800 MW of natural gas-fired electric power plants in development
have been announced in close proximity to Northern Natural Gas' system. Northern
Natural Gas has been  successful in competing  for a  significant  amount of the
increased  demand related to the  construction  of new power and ethanol plants.
Over the last five years, Northern Natural Gas has contracted  approximately 430
mmcf  per day of  volume  on its  system  from  such  new  facilities,  of which
approximately  258 mmcf per day is  currently in service and  approximately  172
mmcf per day is scheduled to begin service between 2003 and 2005.

CE ELECTRIC UK

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

In December 1996, CE Electric UK Ltd., an indirect wholly owned subsidiary of CE
Electric UK, acquired Northern Electric. Northern Electric was one of the twelve
original United Kingdom regional electric  companies that came into existence in
1990 as a  result  of the  restructuring  and  subsequent  privatization  of the
electricity industry that occurred in the United Kingdom. On September 21, 2001,
CE Electric UK Ltd.  acquired  94.75% of  Yorkshire  from  Innogy  Holdings  plc
("Innogy"),  and  simultaneously  sold Northern  Electric's  electricity and gas
supply and metering  businesses to Innogy. The Company sometimes refers to these
transactions  as the "Yorkshire  Swap".  In August 2002, CE Electric UK acquired
the  remaining  5.25% of Yorkshire  that it did not already own from Xcel Energy
International ("Xcel Energy"), an affiliate of Xcel Energy Inc.

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

Descriptions of the functional business units of each of Northern Electric's and
Yorkshire's distribution businesses are set forth below.

Electricity Distribution
------------------------

Northern  Electric's  and  Yorkshire's   operations  consist  primarily  of  the
distribution  of  electricity  and  other  auxiliary  businesses  in the  United
Kingdom.  Northern Electric's and Yorkshire's  distribution  licensee companies,
Northern  Electric  Distribution  Limited  ("NEDL"),  and Yorkshire  Electricity
Distribution plc ("YEDL"),  respectively,  receive electricity from the national
grid  transmission  system and distribute it to their customers'  premises using
their network of transformers,  switchgear and cables.  Substantially all of the
customers in NEDL's and YEDL's  distribution  service areas are connected to the
NEDL and YEDL  networks  and  electricity  can only be delivered  through  their
distribution  system, thus providing NEDL and YEDL with distribution volume that
is relatively stable from year to year. NEDL and YEDL charge fees for the use of
the distribution  system to the suppliers of electricity.  The suppliers,  which
purchase  electricity  from  generators  and sell the  electricity  to  end-user
customers,  use NEDL's and YEDL's distribution  networks pursuant to an industry
standard "Use of System  Agreement" which NEDL and YEDL separately  entered into
with the various  suppliers  of  electricity  in their  respective  distribution
areas.  The  fees  that  may be  charged  by NEDL  and  YEDL  for  use of  their
distribution  systems  are  controlled  by  a  prescribed  formula  that  limits
increases  (and may require  decreases)  based upon the rate of inflation in the
United Kingdom and other regulatory action.

At  December  31,  2002,  NEDL's and  YEDL's  electricity  distribution  network
(excluding  service  connections  to  consumers)  on a combined  basis  included
approximately  31,000  kilometers  of overhead  lines and  approximately  65,000
kilometers of underground cables. In addition to the circuits referred to above,
at December 31, 2002,  NEDL's and YEDL's  distribution  facilities also included
approximately   57,000   transformers  and  approximately   58,000  substations.
Substantially all substations are owned in freehold, and most of the balance are
held on leases that will not expire within 10 years.

                                      -11-
<PAGE>

Utility Services
----------------

Integrated  Utility Services Limited ("IUS"), a subsidiary of Northern Electric,
is  an  engineering   contracting  company  whose  main  business  is  providing
electrical  connection  services  on behalf of NEDL's  and  YEDL's  distribution
businesses and providing electrical infrastructure contracting services to third
parties.

Gas Exploration and Production
------------------------------

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

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

In addition to retaining  its interest in the Victor Field and the ETS pipeline,
CE Gas retained  certain  development  interests in Poland  (Polish  Trough) and
Australia (Perth, Bass and Otway Basins).

                                      -12-

<PAGE>

CALENERGY GENERATION - DOMESTIC

Business

Through  CalEnergy  Generation  - Domestic,  the Company  owns  interests  in 15
operating  non-utility power projects in the United States.  The following table
sets  out  certain  information   concerning   CalEnergy   Generation-Domestic's
non-utility power projects in operation as of December 31, 2002:

<TABLE>
<CAPTION>

                                 FACILITY NET                                     PURCHASE
                                   CAPACITY     NET MW                           AGREEMENT
    OPERATING PROJECT              (MW) (1)     OWNED (1)  FUEL     LOCATION     EXPIRATION     POWER PURCHASER (2)
----------------------          -------------   ---------  ----    ----------    -----------    -------------------

<S>                                   <C>          <C>                              <C>         <C>
Cordova ......................        537          537      Gas     Illinois        2017        El Paso/MidAmerican Energy
Salton Sea I .................         10            5      Geo    California       2017           Edison
Salton Sea II ................         20           10      Geo    California       2020           Edison
Salton Sea III ...............         50           25      Geo    California       2019           Edison
Salton Sea IV ................         40           20      Geo    California       2026           Edison
Salton Sea V .................         49           25      Geo    California    Year-to-year   El Paso/Minerals(3)
Vulcan .......................         34           17      Geo    California       2016           Edison
Elmore .......................         38           19      Geo    California       2018           Edison
Leathers .....................         38           19      Geo    California       2019           Edison
Del Ranch ....................         38           19      Geo    California       2019           Edison
CE Turbo .....................         10            5      Geo    California    Year-to-year   El Paso/Minerals(3)
Saranac ......................        240           90      Gas     New York        2009           NYSE&G
Power Resources ..............        200          100      Gas      Texas          2003            TXU
Yuma .........................         50           25      Gas     Arizona         2024           SDG&E
Roosevelt Hot Springs (4) ....         23           17      Geo    California    Year-to-year       UP&L
                                    -----          ---
DOMESTIC OPERATING PROJECTS ..      1,377          933
                                    =====          ===
</TABLE>

(1)  Represents  accredited  net  generating  capability.  Actual  MW  may  vary
     depending on operating  conditions and plant design. Net MW owned indicates
     current legal ownership,  but, in some cases,  does not reflect the current
     allocation of partnership distributions.

(2)  El  Paso  Corporation  ("El  Paso");  Southern  California  Edison  Company
     ("Edison"); CalEnergy Minerals LLC ("Minerals"), a zinc facility owned by a
     subsidiary  of the  Company;  New York  State  Electric  & Gas  Corporation
     ("NYSE&G"),  TXU  Generation  Company LP ("TXU");  San Diego Gas & Electric
     Company ("SDG&E"), and Utah Power & Light Company ("UP&L").

(3)  Each contract  governing  power  purchases by Minerals will expire 33 years
     from the date of the initial power delivery  under such contract.  Pursuant
     to a Transaction  Agreement  dated  January 29, 2003,  Salton Sea Power LLC
     ("Salton Sea Power") and CE Turbo LLC ("CE Turbo") began selling  available
     power to a subsidiary of TransAlta  Corporation  ("TransAlta")  on February
     12, 2003 based on percentages of the Dow Jones SP-15 Index.  Such agreement
     will expire on October 31, 2003.

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

Cordova Energy owns a 537 MW gas-fired power plant in the Quad Cities,  Illinois
area that the Company  refers to as the Cordova  Project.  CalEnergy  Generation
Operating  Company,  its indirect wholly owned subsidiary,  operates the Cordova
Project.  The Cordova  Project  commenced  commercial  operations  in June 2001.
Cordova Energy  entered into a power purchase  agreement with a unit of El Paso,
under  which El Paso will  purchase  all of the  capacity  and  energy  from the
project  until  December 31,  2019.  Cordova  Energy has  exercised an option to
recall from El Paso 50% of the output  through May 14, 2004,  reducing El Paso's
purchase obligation to 50% of the output during such period. The recalled output
is being sold to MidAmerican Energy. The Company is aware there have been public
announcements  that El Paso's  financial  condition has deteriorated as a result
of, among other things, reduced liquidity.  The Company will continue to monitor
the situation.

                                      -13-
<PAGE>

MEHC has a 50% ownership interest in CE Generation,  whose affiliates  currently
operate ten geothermal  plants (the "Imperial Valley  Projects") in the Imperial
Valley in  California.  The "Salton Sea  Projects"  consist of the Salton Sea I,
Salton  Sea II,  Salton Sea III,  Salton  Sea IV and Salton Sea V Projects  (the
"Salton  Sea I  Project",  the  "Salton  Sea II  Project",  the  "Salton Sea III
Project,"  the  "Salton  Sea  IV  Project,"  and  the  "Salton  Sea  V  Project"
respectively).  The  "Partnership  Projects"  consist  of  the  Vulcan,  Elmore,
Leathers,  Del Ranch and CE Turbo  projects  (the "Vulcan  Project," the "Elmore
Project",  the "Leathers  Project",  the "Del Ranch  Project," and the "CE Turbo
Project"  respectively).  The CE Turbo  Project  and the  Salton  Sea V  Project
commenced commercial operations in 2000.

Each of the Imperial  Valley  Projects,  excluding the Salton Sea V and CE Turbo
Projects,  sells electricity to Edison pursuant to a separate Standard Offer No.
4 Agreement ("SO4  Agreement") or a negotiated  power purchase  agreement.  Each
power  purchase  agreement is  independent  of the others,  and the  performance
requirements  specified  within one such  agreement  apply only to the  project,
which is subject to the  agreement.  The power purchase  agreements  provide for
energy  payments,  capacity  payments and capacity bonus payments.  Edison makes
fixed annual  capacity  payments and capacity  bonus  payments to the applicable
projects to the extent that capacity  factors  exceed  certain  benchmarks.  The
price  for  capacity  was  fixed  for  the  life of the  SO4  Agreements  and is
significantly higher in the months of June through September.

Energy  payments for the SO4 Agreements  were at increasing  fixed rates for the
first ten years after firm  operation and thereafter at a rate based on the cost
that Edison  avoids by purchasing  energy from the project  instead of obtaining
the energy from other sources  ("Avoided Cost of Energy").  In June and November
2001,  the Imperial  Valley  Projects,  which receive  Edison's  Avoided Cost of
Energy,  entered into  agreements that provide for amended energy payments under
the SO4 Agreements.  The amendments provide for fixed energy payments per kWh in
lieu of Edison's Avoided Cost of Energy. The fixed energy payment was 3.25 cents
per kWh from  December 1, 2001 through  April 30, 2002 and is 5.37 cents per kWh
commencing May 1, 2002 for a five-year  period.  Following the five-year period,
the energy payments revert back to Edison's Avoided Cost of Energy.

For the years ended  December 31, 2002,  2001 and 2000,  respectively,  Edison's
Average  Avoided Cost of Energy was 3.5 cents per kWh, 7.4 cents per kWh and 5.8
cents per kWh, respectively. Estimates of Edison's future Avoided Cost of Energy
vary substantially from year to year.

The Salton Sea V and CE Turbo  projects  began  operations in 2000 and, when the
Zinc Recovery Project (defined below) achieves 100% production, the Salton Sea V
Project and the CE Turbo Project would expect to sell approximately 22 MW to the
Zinc Recovery Project at a price based on market transactions.  The remainder is
being sold through other market transactions.

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

The Power  Resources  Project  is a 200 net MW  natural  gas-fired  cogeneration
project  located  near Big Spring,  Texas,  which has a 15-year  power  purchase
agreement with TXU  Generation  Company LP,  formerly  known as Texas  Utilities
Electric Company expiring in 2003. The Power Resources Project is a QF and has a
steam  purchase  agreement  with Alon USA,  L.P. On  December  30,  2002,  Power
Resources obtained an exempt wholesale generator order from the FERC. The status
as an exempt wholesale  generator would  facilitate the Power Resources  Project
sale of energy in market transactions.

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

The Roosevelt  Hot Springs  Project is a geothermal  steam field which  supplies
geothermal  steam  to a 23 net MW  power  plant  owned  by UP&L  located  on the
Roosevelt Hot Springs property under a 30-year steam sales contract  expiring in
2020. The Company  obtained a cash  prepayment  under a pre-sale  agreement with
UP&L

                                      -14-
<PAGE>

whereby  UP&L paid in advance  for the steam  produced by the steam  field.  The
Company  guarantees the  performance of this  subsidiary.  The Company must make
certain  penalty  payments to UP&L if the steam  produced  does not meet certain
quantity and quality requirements.

Zinc Recovery Project
---------------------

Minerals  developed  and  owns  the  rights  to  proprietary  processes  for the
extraction of zinc from elements in solution in the geothermal  brine and fluids
utilized at the Imperial  Valley  Projects.  A plant has  successfully  produced
commercial quality zinc at the projects.  The affiliates of Minerals may develop
facilities  for the  extraction of manganese,  silica and other products as they
further develop the extraction technology.

Minerals  constructed the Zinc Recovery  Project,  which is recovering zinc from
the  geothermal  brine  (the  "Zinc  Recovery  Project").  Facilities  have been
installed  near the Imperial  Valley  Projects  sites to extract a zinc chloride
solution  from the  geothermal  brine  through  an ion  exchange  process.  This
solution is being  transported to a central  processing  plant where zinc ingots
are being  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.  Limited  production  began  during
December 2002 and full  production is expected by late-2003.  In September 1999,
Minerals entered into a sales agreement  whereby all high-grade zinc produced by
the Zinc Recovery Project will be sold to Cominco,  Ltd. The initial term of the
agreement expires in December 2005.

Development Projects
--------------------

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

The Company's subsidiary, CE Obsidian Energy LLC ("Obsidian"), is evaluating the
development of a 185 net MW geothermal facility in Imperial Valley,  California.
Substantially  all the  output  of the  facility  will  be sold to the  Imperial
Irrigation  Disctrict  pursuant to a power purchase  agreement.  An affiliate of
TransAlta has elected to  participate  in the ownership and  development of this
project at a level of 50%. On July 29, 2002,  Obsidian filed an application  for
certification   seeking  approval  from  the  California  Energy  Commission  to
construct and operate the facility.

CALENERGY GENERATION - FOREIGN

Business
--------

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

                                      -15-

<PAGE>

Operating Projects
------------------

The  following  table  sets  out  certain   information   concerning   CalEnergy
Generation-Foreign's  non-utility power projects in operation as of December 31,
2002:
<TABLE>
<CAPTION>

                                FACILITY NET                                      POWER
                                   CAPACITY     NET MW              COMMERCIAL   PURCHASER/
     OPERATING PROJECT (1)         (MW) (2)    OWNED (2)   FUEL    OPERATION    GUARANTOR (3)
-------------------------------- ------------  ---------  ------  ------------  -------------

<S>                                   <C>         <C>                 <C>       <C>
Upper Mahiao ...................      119         119      Geo        1996      PNOC-EDC/ROP
Mahanagdong ....................      165         155      Geo        1997      PNOC-EDC/ROP
Malitbog .......................      216         216      Geo      1996-97      PNOC-EDC/ROP
Casecnan (4) ...................      150         150      Hydro      2001        NIA/ROP
                                      ---         ---
INTERNATIONAL OPERATING PROJECTS      650         640
                                      ===         ===
</TABLE>

(1)  All  operating  projects  are  located in the  Philippines;  all  operating
     projects are governed by contracts which are payable in U.S.  dollars;  and
     all operating projects carry political risk insurance.

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

(3)  PNOC-Energy   Development   Corporation   ("PNOC-EDC"),   Republic  of  the
     Philippines  ("ROP"), and 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.

(4)  Net MW Owned is subject to repurchase rights of up to 15% of the project by
     an  initial  minority  shareholder  and a dispute  with the  other  initial
     minority shareholder  regarding an additional 15% of the project.  Also see
     "Legal Proceedings-Philippines."

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

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

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

The  Mahanagdong  Project is a 165 net MW  geothermal  power  project  owned and
operated by CE Luzon Geothermal Power Company,  Inc. ("CE Luzon"),  a Philippine
corporation  of which the  Company  indirectly  owns 100% of the  common  stock.
Another  industrial  company owns an approximate 6% preferred equity interest in
the  Mahanagdong  Project.  The  Mahanagdong  Project  has  been  in  commercial
operation  since  July 25,  1997.  The  Mahanagdong  Project  sells  100% of its
capacity on a similar basis as described  above for the Upper Mahiao  Project to
PNOC-EDC,  which in turn  sells  the  power to the NPC for  distribution  on the
island of Luzon.

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

                                      -16-
<PAGE>

a performance undertaking.

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

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

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

CE Casecnan  Ltd.  ("CE  Casecnan"),  the Company's  indirectly  majority  owned
subsidiary,  operates the Casecnan Project, a combined irrigation and 150 Net MW
hydroelectric power generation project.  The Casecnan Project consists generally
of diversion  structures in the Casecnan and Taan rivers that capture and divert
excess water in the Casecnan watershed by means of concrete, in-stream diversion
weirs and transfer that water through a transbasin  tunnel of  approximately  23
kilometers (including the intake adit from the Taan to the Casecnan river), with
a diameter  of  approximately  6.5  meters to an  existing  underutilized  water
storage  reservoir at  Pantabangan.  During the water  transfer,  the  elevation
differences  between the two watersheds allows electrical energy to be generated
at a 150 MW rated  capacity  power  plant,  which is located  in an  underground
powerhouse cavern at the end of the water tunnel. A tailrace discharge tunnel of
approximately  three kilometers delivers water from the water tunnel and the new
powerhouse  to  the  Pantabangan  reservoir,   providing  additional  water  for
irrigation and increasing the potential electrical  generation at two downstream
existing  hydroelectric  facilities of the Philippine National Power Corporation
("NPC"),  the  government-owned  and controlled  corporation that is the primary
supplier of electricity in the Philippines.  Since the water has been determined
to remain suitable for irrigation  throughout the Casecnan Project operations of
capturing,  diverting and transferring the water,  other than removing sediments
at the diversion structures,  no treatment is required. Once in the reservoir at
Pantabangan, the water is under the control of, and for the use of the NIA.

CE Casecnan constructed and operates the Casecnan Project under the terms of the
Project Agreement between CE Casecnan and NIA. Under the Project  Agreement,  CE
Casecnan  developed,  financed and constructed  the Casecnan  Project during the
construction  period and will own and  operate  the  Project  during the 20-year
Cooperation  Period.  During the Cooperation  Period, NIA is obligated to accept
all  deliveries  of water and  energy,  and so long as the  Casecnan  Project is
physically  capable of operating and delivering in accordance with agreed levels
set forth in the Project Agreement, NIA will pay CE Casecnan a fixed fee for the
delivery  of water and a fixed fee for the  delivery  of a  threshold  amount of
electricity.  In addition,  NIA will pay a fee for all electricity  delivered in
excess of the threshold amount up to a specified amount.  The water delivery fee
is a fixed  monthly  amount,  to be  received  in US  dollars at the end of each
month, based on 801.9 million cubic meters of water flow past the water delivery
point per year, pro-rated to 66.8 million cubic meters per month. The unit price
for water is established at $0.029 per cubic meter (subject to adjustment as set
forth in the Project Agreement) as of January 1, 1994 and escalated at seven and
one-half percent (7.5%) per annum, pro-rated on a monthly basis, through the end
of the fifth year of the Cooperation Period and then kept flat at that level for
the last fifteen years of the Cooperation Period. The unit price for water is to
be adjusted by $.00043 for each $1.0  million of certain  taxes and fees paid by
the Company as specified in the Project Agreement. The unit price of water as of
December 31 2002 is $0.1017.  Actual  deliveries  of water  greater than or less
than 66.8 million cubic meters in any month will not result in any adjustment of
the water delivery fee. The guaranteed  energy fee is a fixed monthly amount, to
be received in US dollars at the end of each month,  based on energy  deliveries
of 228.0 million kWh per year,  pro-rated to 19.0 million kWh per month.  Actual
deliveries of energy less than 19.0 million kWh per month will not result in any
reduction of the  guaranteed  energy fee but will result in an adjustment to the
excess energy fee. The unit price for

                                      -17-
<PAGE>

guaranteed  energy is  $0.1596  per kWh.  The  excess  energy  fee is a variable
amount,  to be received in US dollars at the end of each month,  for  electrical
energy  delivered in that month in excess of 19.0 million kWh. No excess  energy
delivery fee will be due until all cumulative electrical energy shortfalls below
19.0 million kWh in previous  months have been made up. The unit price of excess
energy is $0.1509 per kWh.  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 US  dollars.  The fixed  fees paid for the
delivery of water and energy,  regardless of the amount of  electricity or water
actually delivered,  are expected to provide  approximately 78% of CE Casecnan's
revenues.  At the end of the Cooperation  Period,  the Casecnan  Project will be
transferred to NIA at no additional consideration on an "as is" basis.

The ROP has provided a  Performance  Undertaking  under which NIA's  obligations
under the Project  Agreement are  guaranteed by the full faith and credit of the
ROP.  The Project  Agreement  and the  Performance  Undertaking  provide for the
resolution of disputes by binding  arbitration in Singapore under  international
arbitration rules.

HOMESERVICES

Business
--------

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

HomeServices' 2002 Acquisitions
-------------------------------

In 2002, HomeServices  separately acquired three real estate companies.  For the
year ended December 31, 2001,  these real estate  companies had combined revenue
of  approximately  $356.0  million on 42,000  closed  sides  representing  $13.7
billion of sales volume.

                                      -18-

<PAGE>

REGULATORY MATTERS

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

MIDAMERICAN ENERGY

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

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

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

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

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

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 MidAmerican
Energy which would result in increased  compliance costs,  could have a material
adverse effect on its results of operations.

Under  a  settlement  agreement  approved  by the  IUB  on  December  21,  2001,
MidAmerican Energy's Iowa retail rates in effect

                                      -19-
<PAGE>

on December 31, 2000 are frozen  through  December 31, 2005.  In approving  that
settlement,  the IUB specifically  allows the filing of the electric rate design
and/or cost of service rate  changes  that are intended to keep overall  company
revenue unchanged but could result in changes to individual  tariffs.  Under the
2001  settlement  agreement  further  provides  that an  amount  equal to 50% of
revenues  associated with Iowa retail electric returns on equity between 12% and
14%,  and 83.33% of revenues  associated  with Iowa retail  electric  returns on
equity above 14%, in each year is recorded as a regulatory  liability to be used
to offset a portion of the cost to Iowa  customers  of future  generating  plant
investment.  An  amount  equal to the  regulatory  liability  is  recorded  as a
regulatory charge in depreciation and amortization expense when the liability is
accrued.  Interest expense is accrued on the portion of the regulatory liability
related to prior years.  Beginning in 2002, the liability is being reduced as it
is credited against allowance for funds used during  construction or capitalized
financing costs associated with generating  plant additions.  As of December 31,
2002, the related regulatory liability was $102.9 million.

On March 20, 2003,  MidAmerican  Energy and the Iowa Office of Consumer Advocate
agreed upon a settlement proposal in which the rate freeze described above would
be extended  through  December  31, 2010.  Under the  settlement  proposal,  for
calendar years 2006 through 2010, an amount equal to 40% of revenues  associated
with Iowa retail  electric  returns on equity between  11.75% and 13.0%;  50% of
revenues  associated with Iowa retail  electric  returns on equity between 13.0%
and 14.0%; and 83.3% of revenues associated with Iowa retail electric returns on
equity  greater  than 14.0% will be applied as a reduction to offset some of the
capital costs on the Iowa portion of three generation  projects.  If Iowa retail
electric  returns on equity fall below 10% in any 12-month  period after January
1, 2006,  MidAmerican  Energy has the ability to file for a general  increase in
rates under the  proposed  settlement.  The  proposed  settlement  is subject to
approval  by the IUB and  requires  enactment  of Iowa  legislation.  The IUB is
expected to rule on the proposal during the second half of 2003.

Under an  Illinois  restructuring  law  enacted in 1997,  as amended in 2002,  a
sharing mechanism is in place for MidAmerican Energy's Illinois regulated retail
electric  operations whereby earnings above a computed level of return on common
equity  will  be  shared  equally  between  customers  and  MidAmerican  Energy.
MidAmerican  Energy's  computed  level of return on common  equity is based on a
rolling  two-year  average of the Monthly  Treasury  Long-Term  Average Rate, as
published by the Federal Reserve System, plus a premium of 8.5% for 2000 through
2004 and a premium of 12.5% for 2005 and 2006. The two-year  average above which
sharing  must occur for 2002 was 14.03%.  The law allows  MidAmerican  Energy to
mitigate the sharing of earnings  above the  threshold  return on common  equity
through accelerated recovery of regulatory assets.

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

KERN RIVER AND NORTHERN NATURAL GAS

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

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

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

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

                                      -20-
<PAGE>

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

Northern Natural Gas' current tariff structure provides for:

     o    seasonality in demand rates;

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

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

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

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

In 2000,  the FERC  issued new rules with  respect  to terms and  conditions  of
interstate pipeline  transportation  service pursuant to Order No. 637. In Order
No.  637,  the  FERC  made  changes  to its  regulatory  model  to  enhance  the
effectiveness  and efficiency of gas markets as they evolved since the series of
FERC orders  commonly  referred  to as Order No. 436,  No. 500 and No. 636 which
were adopted  beginning in the  mid-1980s to the early 1990s and which  provided
for the restructuring of interstate  pipeline sales and services.  Specifically,
in Order No. 637 the FERC:

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

     o    revised certain reporting requirements; and

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

On July 17, 2000,  Northern  Natural Gas made its initial  compliance  filing in
accordance with Order No. 637. Northern Natural Gas made a revised Order No. 637
compliance filing on March 4, 2002 and a supplemental filing on May 10, 2002. On
November 21, 2002,  the FERC issued an Order on Compliance  with Order Nos. 637,
587-G and 587-L.  In the November 21, 2002 Order,  the FERC found that  Northern
Natural Gas generally complied with Order Nos. 637, 587-G and 587-L,  subject to
certain  modifications,  and ordered  Northern  Natural  Gas to file  compliance
tariffs within 30 days.  Northern filed in compliance with the November 21, 2002
order on December 21, 2002. At this time,  an order on  Compliance  has not been
issued.  In addition,  numerous  parties filed for rehearing of the November 21,
2002 order, which are also pending.

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

The FERC also has authority over gas pipelines' accounting  practices.  The FERC
recently issued a notice of proposed rulemaking  regarding gas accounting issues
which  would limit the ability of gas  pipelines  to enter into cash  management
agreements  with  their  parent  companies.  The  Company  is in the  process of
reviewing  such  proposed  rule,  but the Company does not believe the rule will
have a material adverse impact on it and its pipeline subsidiaries.

On August 1, 2002,  the FERC issued an Order to respond to Northern  Natural Gas
related to Northern  Natural  Gas'

                                      -21-
<PAGE>

existing $450.0 million  revolving credit facility and to cash management record
keeping by Northern Natural Gas. Pursuant to a Stipulation and Consent Agreement
dated August 8, 2002, Northern Natural Gas agreed to comply with the FERC's cash
management  practices and to not include the costs  associated with its existing
$450.0 million revolving credit facility in any future rate proceeding.

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

OTHER UNITED STATES REGULATION

The Public Utility Regulatory  Policies Act of 1978, as amended  ("PURPA"),  and
the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), are two of
the laws  (including  the  regulations  thereunder)  that affect the Company and
certain  of  its  subsidiaries'  operations.   PURPA  provides  to  QFs  certain
exemptions   from   federal   and   state   laws  and   regulations,   including
organizational,  rate and financial regulation.  PUHCA extensively regulates and
restricts the  activities of registered  public  utility  holding  companies and
their  subsidiaries.  Congress is currently  considering  major  changes to both
PUHCA and PURPA. Any such legislation,  if adopted, could vary considerably from
the terms contained in either or both of the House and Senate versions which are
presently under consideration. The Company believes that if the current proposed
legislation  is passed,  it would apply to new projects only and thus,  although
potentially impacting its ability to develop new domestic projects, it would not
affect the Company's existing qualifying facilities.  The Company cannot provide
assurance,   however,  that  legislation,   if  passed,  or  any  other  similar
legislation  proposed in the future,  would not  adversely  impact its  existing
domestic projects.

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

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

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

                                      -22-
<PAGE>

CE ELECTRIC UK

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

Under the Utilities Act 2000,  the public  electricity  supply  license  created
pursuant to the Electricity  Act 1989 was replaced by two separate  licenses-the
electricity  distribution  license and the electricity supply license.  When the
relevant  provision  of the  Utilities  Act 2000 became  effective on October 1,
2001, the public  electricity supply licenses formerly held by Northern Electric
and  Yorkshire  were  split so that  separate  subsidiaries  held  licenses  for
electricity  distribution  and electricity  supply.  In order to comply with the
Utilities Act 2000 and to facilitate this license  splitting,  Northern Electric
and Yorkshire  (and each of the other  holders of the former public  electricity
supply licenses) each made a statutory  transfer scheme that was approved by the
Secretary  of State for Trade  and  Industry.  These  schemes  provided  for the
transfer of certain assets and  liabilities to the licensed  subsidiaries.  This
occurred on October 1, 2001, a date set by the  Secretary of State for Trade and
Industry.  As a  consequence  of these  schemes,  the  electricity  distribution
businesses of Northern Electric and Yorkshire were transferred to NEDL and YEDL,
respectively.  NEDL and YEDL are each  holders  of an  electricity  distribution
license.   The  residual  elements  of  the  Electricity  Supply  licenses  were
transferred  to  Innogy  in  connection  with  the sale of  Northern  Electric's
electricity and gas supply business to Innogy and the retention by Innogy of the
electricity and gas supply business of Yorkshire, all as a part of the Yorkshire
Swap on September 21, 2001.

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

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

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

     o    the actual operating costs of each of the licensees;

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

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

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

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

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

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

For the duration of the current regulatory period, the 1999 review also requires
that regulated distribution revenue per unit

                                      -23-
<PAGE>

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

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

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

CALENERGY GENERATION - DOMESTIC

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

CORDOVA ENERGY AND POWER RESOURCES

Cordova  Energy and Power  Resources  are exempt  from  regulation  under  PUHCA
because  they are exempt  wholesale  generators.  Power  Resources is also a QF.
PUHCA  provides that an exempt  wholesale  generator is not  considered to be an
electric  utility company.  An exempt  wholesale  generator is permitted to sell
capacity  and  electricity  in the  wholesale  markets,  but  not in the  retail
markets.

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

CALENERGY GENERATION - FOREIGN

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

In connection with an interagency  review of approximately 40 independent  power
project  contracts in the  Philippines,  the Casecnan  Project  (along with four
other  unrelated  projects) has reportedly  been identified as raising legal and
financial  questions  and,  with  those  projects,   has  been  prioritized  for
renegotiation.   The  Company's   subsidiaries'  Upper  Mahiao,   Malitbog,  and
Mahanagdong projects,  which,  together with the Casecnan Project,  collectively
referred to as the Philippine

                                      -24-
<PAGE>

Projects,  have also reportedly been identified as raising financial  questions.
No written  report has yet been issued with respect to the  interagency  review,
and the timing and nature of steps,  if any that the  Philippine  Government may
take in this regard are not known.  Accordingly,  it is not known what,  if any,
impact the  government's  review will have on the  operations  of the  Company's
Philippines Projects. CE Casecnan representatives, together with certain current
and former government officials,  were requested to appear and did appear during
2002 before a Philippine  Senate  committee which has raised  questions and made
allegations  with  respect  to  the  Casecnan  Project's  tariff  structure  and
implementation.  No further Senate  hearings are scheduled at this time although
hearings  before a  Philippine  House  committee  were  scheduled  for the first
quarter of 2003.

HOMESERVICES

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

PIPELINE SAFETY REGULATION

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

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

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

ENVIRONMENTAL REGULATION

Domestic
--------

The Company is subject to a number of federal, state and local environmental and
environmentally  related  laws and  regulations  affecting  many  aspects of its
present and future  operations in the United States.  Such laws and  regulations
generally  require  the  Company  to obtain and  comply  with a wide  variety of
licenses,  permits and other approvals.  The Company believes that its operating
power  facilities  and  gas  pipeline   operations  are  currently  in  material
compliance with all applicable  federal,  state and local laws and  regulations.
However,  no guarantee  can be given that in the future the Company will be 100%
compliant with all applicable environmental statutes and regulations or that all
necessary permits will be obtained or approved. In addition, the construction of
new power facilities and gas pipeline  operations is a costly and time-consuming
process  requiring a multitude of complex  environmental  permits and  approvals
prior to the start of construction  that may create the risk of expensive delays
or material  impairment of project value if projects  cannot function as planned
due to  changing  regulatory  requirements  or  local  opposition.

                                      -25-
<PAGE>

The Company cannot assure you that existing  regulations  will not be revised or
that new regulations will not be adopted or become  applicable to it which could
have an adverse impact on its operating costs and operations.

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

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

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

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

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

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

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

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

                                      -26-
<PAGE>

environmental equipment installed as a result of such plan.

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

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

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

MidAmerican  Energy has evaluated or is  evaluating 27 properties  that were, at
one time, sites of gas manufacturing plants in which MidAmerican Energy may be a
potentially  responsible  party.  MidAmerican  Energy  estimates  the  range  of
possible costs for investigation,  remediation and monitoring for these sites to
be $16 million to $54 million.  As of December 31, 2002,  MidAmerican Energy has
recorded a  liability  of $17  million  for these  sites.  MidAmerican  Energy's
present rates in Iowa provide for a fixed annual  recovery of  manufactured  gas
plant costs.

Pursuant to the Toxic Substances  Control Act, a federal law administered by the
EPA, MidAmerican Energy developed a comprehensive program for the use, handling,
control and disposal of all  polychlorinated  biphenyls,  or PCBs,  contained in
electrical  equipment.  The  future  use of  equipment  containing  PCBs will be
minimized. Capacitors,  transformers and other miscellaneous equipment are being
purchased with a non-PCB dielectric fluid.  MidAmerican Energy's exposure to PCB
liability has been reduced  through the orderly  replacement of a number of such
electrical devices with similar non-PCB electrical devices.

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

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

                                      -27-

<PAGE>

United Kingdom
--------------

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

The United Kingdom  government  introduced new contaminated  land legislation in
April  2000  that  requires  local  authorities  to put in place a  program  for
investigating land in their area in order to identify contamination.

     o    Local  authorities can leave remediation  notices where  contamination
          poses a threat to the greater environment.

     o    If the "person" who  contaminated  the land cannot be found,  the land
          owner is responsible.

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

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

The 1998 Groundwater  Regulations  seek to prevent listed  hazardous  substances
from  entering  groundwater  and  strengthens  the  United  Kingdom  Environment
Agency's powers to require additional  protective measures,  especially in areas
of important groundwater supplies. Mineral oils and hydrocarbons are included in
the list of more  tightly  controlled  substances  ("List I  substances").  This
affects the high voltage fluid filled electricity cable network incorporating an
insulating fluid that is currently in List I. The existing  voluntary  Operating
Code of Practice,  as agreed between the Environment  Agency and the Electricity
Supply  Industries,   is  undergoing   revision  through  the  services  of  the
Electricity   Association  to  address  the  regulatory  changes.  The  existing
voluntary  Operating  Code of  Practice  is, and any revised  Operating  Code of
Practice will be,  incorporated  into the operating  practices of NEDL and YEDL.
Any  revisions  which are made are not expected to have a  significant  material
impact on the Company.

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

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

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

                                      -28-
<PAGE>

pending against CE Electric UK with respect to any environmental matter.

Environmental  laws and  regulations in the United Kingdom  currently  have, and
future modifications may increasingly have, the effect of requiring modification
of CE Electric UK's facilities and increasing its operating costs.

PHILIPPINES

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

NUCLEAR REGULATION

Under the Nuclear  Waste Policy Act of 1982,  the United  States  Department  of
Energy is responsible for the selection and development of repositories for, and
the permanent disposal of, spent nuclear fuel and high-level radioactive wastes.
Exelon Generation,  as required by the Nuclear Waste Act, signed a contract with
the  Department  of Energy to provide for the disposal of spent nuclear fuel and
high-level  radioactive  waste  beginning  not  later  than  January  1998.  The
Department of Energy did not begin receiving spent nuclear fuel on the scheduled
date, and it is expected that the schedule will be  significantly  delayed.  The
costs  incurred by the  Department of Energy for disposal  activities  are being
financed  by  fees  charged  to  owners  and  generators  of the  waste.  Exelon
Generation  has  informed  MidAmerican  Energy  that  existing  on-site  storage
capability at Quad Cities Station is sufficient to permit  interim  storage into
2005. For Quad Cities Station, Exelon Generation has informed MidAmerican Energy
that it plans to develop interim spent fuel storage  installation at Quad Cities
Station to store additional spent nuclear fuel in dry casks.  Exelon  Generation
expects the bulk of the construction work will be done in 2004.

MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its
license and 25% ownership  interest in Quad Cities Station Units 1 and 2. Exelon
Generation  is the operator of Quad Cities  Station and is under  contract  with
MidAmerican  Energy to secure and keep in effect all  necessary NRC licenses and
authorizations.

The NRC  regulations  control  the  granting  of permits  and  licenses  for the
construction  and  operation  of nuclear  generating  stations  and subject such
stations to  continuing  review and  regulation.  The NRC review and  regulatory
process covers, among other things, operations,  maintenance,  and environmental
and radiological aspects of such stations. The NRC may modify, suspend or revoke
licenses and impose civil penalties for failure to comply with the Atomic Energy
Act, the regulations under such Act or the terms of such licenses.

Federal  regulations provide that any nuclear operating facility may be required
to cease operation if the NRC determines there are deficiencies in state,  local
or utility  emergency  preparedness  plans  relating to such  facility,  and the
deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy
that an emergency preparedness plan for Quad Cities Station has been approved by
the NRC. Exelon  Generation has also advised  MidAmerican  Energy that state and
local plans  relating to Quad Cities  Station have been  approved by the Federal
Emergency Management Agency.

The NRC also regulates the decommissioning of nuclear power plants including the
planning  and  funding  for  the  eventual  decommissioning  of the  plants.  In
accordance with these  regulations,  MidAmerican  Energy submits a report to the
NRC  every  two  years  providing  "reasonable  assurance"  that  funds  will be
available to pay the costs of decommissioning its share of Quad Cities Station.

MidAmerican  Energy has established  external trusts for the investment of funds
collected  for nuclear  decommissioning  associated  with Quad  Cities  Station.
Electric  tariffs   currently  in  effect  include   provisions  for  annualized
collection of estimated  decommissioning  costs at Quad Cities Station. In Iowa,
Quad  Cities  Station   decommissioning  costs  are  reflected  in  base  rates.
MidAmerican  Energy's cost related to  decommissioning  funding in 2002 was $8.3
million.

                                      -29-
<PAGE>


EMPLOYEES

As of December 31, 2002, the Company and its subsidiaries employed approximately
10,985 people. Approximately 4,205 of which are represented by labor unions.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

     o    weather effects on sales and revenue;

     o    general industry trends;

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

     o    fuel and power costs and availability;

     o    continued availability of accessible gas reserves;

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

     o    availability, term and deployment of capital;

     o    availability of qualified personnel;

     o    risks relating to nuclear generation;

     o    financial or regulatory  accounting  principles or policies imposed by
          the  Public  Company   Accounting   Oversight   Board,  the  Financial
          Accounting  Standards  Board  ("FASB"),  the  Securities  and Exchange
          Commission ("SEC") and similar entities with regulatory oversight; and

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

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

ITEM 2.  PROPERTIES.

The  Company'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 plants,
natural gas  pipelines,  related  rights-of-way,  compressor  stations and meter
stations.  It is the  opinion  of  management  that  the  principal  depreciable
properties  owned  by the  Company  are in good  operating  condition  and  well
maintained.

                                      -30-

<PAGE>

MIDAMERICAN ENERGY

MidAmerican  Energy's most  significant  properties are its electric  generation
facilities.  For  a  discussion  of  these  generation  facilities,  please  see
"Business-MidAmerican  Energy."  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
natural  gas mains and  services  pipelines,  meters  and  related  distribution
equipment,  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, 2002,
included 290 miles of 345-kV lines and 1,111 miles of 161-kV lines.  MidAmerican
Energy's   electric   distribution   system   included   approximately   218,500
transformers and 377 substations at December 31, 2002.

The gas  distribution  facilities  of  MidAmerican  Energy at December 31, 2002,
included 20,835 miles of gas mains and services.

Substantially  all the former  Iowa-Illinois  Gas and Electric  Company  utility
property and  franchises,  and  substantially  all of the former  Midwest  Power
Systems electric utility property located in Iowa, or approximately 80% of gross
utility plant, is pledged to secure mortgage bonds.

CE ELECTRIC UK

At  December  31,  2002,   Northern   Electric's  and  Yorkshire's   electricity
distribution  networks (excluding service connection to consumers) on a combined
basis   included   approximately   31,000   kilometers  of  overhead  lines  and
approximately  65,000  kilometers  of  underground  cables.  In  addition to the
circuits  referred to above,  at December  31,  2002,  Northern  Electric's  and
Yorkshire's   distribution   facilities  also  included   approximately   57,000
transformers and approximately 58,000 substations.

KERN RIVER AND NORTHERN NATURAL GAS

At December 31, 2002, Kern River's pipeline was comprised of two distinguishable
sections: the mainline and the common facilities.  The 707-mile mainline section
extends from the pipeline's  point of origination in Opal,  Wyoming  through the
Central Rocky  Mountains  area to Daggett,  California  and is owned entirely by
Kern River.  The common  facilities  consist of the 219-mile section of pipeline
that extends from Daggett to Bakersfield,  California. The common facilities are
jointly owned by Kern River (currently  approximately 67.9%) and Mojave Pipeline
Company (currently approximately 32.1%) as tenants-in-common.

At  December  31,  2002,   Northern   Natural  Gas'  system  was   comprised  of
approximately 7,300 miles of mainline transmission pipes and approximately 9,300
miles of smaller  diameter  branch  lines and  laterals.  Northern  Natural Gas'
storage services are provided through the operation of three underground storage
fields,  in  Redfield,  Iowa,  and  Lyons  and  Cunningham,  Kansas.  The  three
underground  natural  gas  storage  facilities  and  Northern  Natural  Gas' two
liquefied  natural gas storage  peaking units have a total  storage  capacity of
approximately 59 Bcf.  Northern  Natural Gas' two LNG  liquefaction/vaporization
facilities are located near Garner,  Iowa and Wrenshall,  Minnesota with storage
capacity of 2 Bcf each.

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

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

The  Company  believes  that  Kern  River  and  Northern  Natural  Gas each have
satisfactory  title  to all of the real  property

                                      -31-
<PAGE>

making up their respective pipelines in all material respects.

OTHER PROPERTIES

         At  December  31,  2002,  the  Company's  most   significant   physical
properties,  other than those owned by MidAmerican  Energy, CE Electric UK, Kern
River and Northern  Natural Gas,  are its current  interests in operating  power
facilities  and  its  plants  under   construction  and  related  real  property
interests,  as well as leases of office  space for its  residential  real estate
brokerage operations. See "Business" for further detail.

ITEM 3. LEGAL PROCEEDINGS.

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

Pipeline Litigation
-------------------

In 1998,  the United  States  Department  of Justice  informed  the then current
owners of Kern River and Northern Natural Gas that Jack Grynberg, an individual,
had filed  claims in the  United  States  District  Court  for the  District  of
Colorado  under the False Claims Act against such  entities and certain of their
subsidiaries  including  Kern River and Northern  Natural Gas. Mr.  Grynberg has
also filed claims against  numerous other energy  companies and alleges that the
defendants  violated the False Claims Act in connection with the measurement and
purchase  of  hydrocarbons.  The  relief  sought  is an  unspecified  amount  of
royalties  allegedly not paid to the federal government,  treble damages,  civil
penalties,  attorneys'  fees and  costs.  On April 9, 1999,  the  United  States
Department  of Justice  announced  that it declined to  intervene  in any of the
Grynberg  qui tam cases,  including  the actions  filed  against  Kern River and
Northern  Natural Gas in the United  States  District  Court for the District of
Colorado.   On  October  21,  1999,  the  Panel  on  Multi-District   Litigation
transferred  the Grynberg qui tam cases,  including  the ones filed against Kern
River and Northern  Natural  Gas, to the United  States  District  Court for the
District of Wyoming for pre-trial  purposes.  Motions to dismiss the  complaint,
filed by various defendants  including Northern Natural Gas and Williams,  which
was the former owner of Kern River,  were denied on May 18, 2001.  On October 9,
2002,  the United States  District  Court for the District of Wyoming  dismissed
Grynberg's Royalty Valuation Claims. Grynberg has appealed this dismissal to the
United States Court of Appeals for the Tenth  Circuit.  In  connection  with the
purchase of Kern River from Williams in March 2002, Williams agreed to indemnify
the Company against any liability for this claim;  however,  no assurance can be
given as to the  ability of  Williams  to perform  on this  indemnity  should it
become necessary.  No such  indemnification  was obtained in connection with the
purchase of Northern  Natural Gas in August 2002. The Company  believes that the
Grynberg  cases filed  against Kern River and  Northern  Natural Gas are without
merit and Williams, on behalf of Kern River pursuant to its indemnification, and
Northern Natural Gas, intend to defend these actions vigorously.

On June 8, 2001, a number of interstate pipeline companies, including Kern River
and Northern  Natural Gas, were named as defendants in a nationwide class action
lawsuit which had been pending in the 26th Judicial  District,  District  Court,
Stevens County Kansas,  Civil  Department  against other  defendants,  generally
pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that
the  defendants  have  engaged in  mismeasurement  techniques  that  distort the
heating  content  of  natural  gas,  resulting  in an  alleged  underpayment  of
royalties to the class of producer plaintiffs.  In November 2001, Kern River and
Northern Natural Gas, along with the coordinating defendants,  filed a motion to
dismiss  under  Rules 9B and 12B of the  Kansas  Rules of  Civil  Procedure.  In
January 2002, Kern River and most of the coordinating  defendants filed a motion
to dismiss for lack of personal jurisdiction. The court has yet to rule on these
motions.  The  plaintiffs  filed for  certification  of the  plaintiff  class on
September  16,  2002.  On  January  13,  2003,  oral  arguments  were  heard  on
coordinating defendants' opposition to class certification.  Williams has agreed
to indemnify the Company  against any liability  associated  with Kern River for
this claim;  however, no assurance can be given as to the ability of Williams to
perform on this indemnity  should it become  necessary.  Williams,  on behalf of
Kern River and other entities, anticipates joining with Northern Natural Gas and
other defendants in contesting  certification of the plaintiff class. Kern River
and Northern  Natural Gas believe that this claim is without merit and that Kern
River's  and  Northern  Natural  Gas' gas  measurement  techniques  have been in
accordance with industry standards and its tariff.

                                      -32-

<PAGE>

Philippines
-----------

Casecnan Construction Arbitration

On February 12, 2001, the contractor  filed a Request for  Arbitration  with the
International  Chamber of  Commerce  seeking  schedule  relief of up to 153 days
through August 31, 2001 resulting from various alleged force majeure events.  In
its March 20,  2001  Supplement  to  Request  for  Arbitration,  the  contractor
requested  compensation for alleged additional costs of approximately $4 million
it incurred from the claimed force majeure  events to the extent it is unable to
recover from its  insurer.  On April 20, 2001,  the  contractor  filed a further
supplement  seeking an additional  compensation for damages of approximately $62
million for the alleged force majeure event (and geologic conditions) related to
the  collapse of the surge  shaft.  The  contractor  also has  alleged  that the
circumstances  in which CE Casecnan  assumed control of the Casecnan Project and
placed  it  into  commercial  operation  on  December  11,  2001  amounted  to a
repudiation of the  construction  contract and has filed a claim for unspecified
quantum  meruit  damages,  and has  further  alleged  that the delay  liquidated
damages  clause which  provides for payments of $125,000 per day for each day of
delay in completion of the Project for which the  contractor is  responsible  is
unenforceable.  The arbitration is being conducted  applying New York law and in
accordance with the rules of the International Chamber of Commerce.

Hearings  have  been held in  connection  with this  arbitration  in July  2001,
September  2001,  January 2002,  March 2002,  November 2002 and January 2003. As
part of those hearings,  on June 25, 2001, the arbitration  tribunal temporarily
enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di
Roma in  support  of the  contractor's  obligations  to CE  Casecnan  for  delay
liquidated damages. As a result of the continuing nature of that injunction,  on
April 26, 2002, CE Casecnan and the contractor  mutually  agreed that no demands
would  be made on the  Banca  di Roma  demand  guaranty  except  pursuant  to an
arbitration  award. As of December 31, 2002,  however,  CE Casecnan has received
approximately $6.0 million of liquidated damages from demands made on the demand
guarantees  posted  by  a  separate  financial  institution  on  behalf  of  the
contractor.  On November 7, 2002, the  International  Chamber of Commerce issued
the arbitration  tribunal's partial award with respect to the contractor's force
majeure and  geologic  conditions  claims.  The  arbitration  panel  awarded the
contractor  18 days of  schedule  relief in the  aggregate  for all of the force
majeure events and awarded the contractor  $3.8 million with respect to the cost
of the collapsed surge shaft. All of the contractor's  other claims with respect
to force majeure and geologic conditions were denied.

Further hearings on the contractor's  repudiation and quantum meruit claims, the
alleged  unenforceability  of the delay  liquidated  damages  clause and certain
other matters had been  scheduled for March 24 through March 28, 2003,  but were
postponed  as a result of the  commencement  of  military  action  in Iraq.  The
arbitral  tribunal has requested  the parties to indicate the earliest  possible
date on which they are available and will then reschedule the hearings.

If the contractor were to prevail on its claim that the delay liquidated damages
clause is unenforceable, CE Casecnan would not be entitled to collect such delay
damages for the period from March 31, 2001 through  December  11,  2001.  If the
contractor  were to prevail in its  repudiation  claim and prove quantum  meruit
damages in excess of amounts already paid to the  contractor,  CE Casecnan could
be liable to make additional  payments to the contractor.  CE Casecnan  believes
all such  allegations and claims are without merit and is vigorously  contesting
the contractor's claims.

Casecnan NIA Arbitration

Under  the  terms  of the  Project  Agreement,  NIA has  the  option  of  timely
reimbursing CE Casecnan  directly for certain taxes CE Casecnan has paid. If NIA
does not so reimburse CE  Casecnan,  the taxes paid by CE Casecnan  result in an
increase in the Water  Delivery  Fee.  The payment of certain  other taxes by CE
Casecnan  results  automatically in an increase in the Water Delivery Fee. As of
December 31, 2002,  CE Casecnan has paid  approximately  $56.7  million in taxes
which as a result of the foregoing provisions has resulted in an increase in the
Water  Delivery Fee. NIA has failed to pay the portion of the Water Delivery Fee
each month  which  relates to the payment of these  taxes by CE  Casecnan.  As a
result of this non-payment,  on August 19, 2002, CE Casecnan filed a Request for
Arbitration  against NIA,  seeking payment of such portion of the Water Delivery
Fee and  enforcement of the relevant  provision of the Project  Agreement  going
forward.  The arbitration  will be conducted in accordance with the rules of the
International  Chamber of  Commerce.  NIA is expected to file its answer late in
the first  quarter  or early in the  second  quarter,  2003.  The  three  member
arbitration  panel has been confirmed by the  International  Chamber of Commerce
and an initial organizational hearing is scheduled for the second quarter, 2003.

Casecnan Stockholder Litigation

Pursuant  to the  share  ownership  adjustment  mechanism  in  the  CE  Casecnan
stockholder  agreement,  which is based

                                      -33-
<PAGE>

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

In February  2003, San Lorenzo Ruiz Builders and  Developers  Group,  Inc. ("San
Lorenzo"),  an  original  shareholder  substantially  all of whose  shares in CE
Casecnan a subsidiary of the Company  purchased in 1998,  threatened to initiate
legal action in the Philippines in connection with certain aspects of its option
to repurchase such shares on or prior to commercial operation of the Project. CE
Casecnan  believes  that San  Lorenzo  has no valid  basis for any claim and, if
named as a defendant in any action that may be  commenced  by San Lorenzo,  will
vigorously defend any such action.

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

Not applicable.

                                      -34-

<PAGE>

                                     PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

Since March 14,  2000,  the  Company's  equity  securities  have been owned by a
limited  group of private  investors and have not been  registered  with the SEC
pursuant to the Securities  Act of 1933, as amended,  listed on a stock exchange
or otherwise publicly held or traded.

                                      -35-

<PAGE>

ITEM 6. SELECTED FINANCIAL DATA.

                      SELECTED CONSOLIDATED FINANCIAL DATA
                             (Amounts in thousands)

The following table sets forth selected historical  consolidated financial data,
which should be read in conjunction with the Company's financial  statements and
the related  notes to those  statements  included in this annual report and with
"Management's  Discussion  and  Analysis of Financial  Condition  and Results of
Operations" appearing elsewhere in this annual report. The selected consolidated
data as of and for the years ended  December  31, 2002 and 2001,  as of December
31, 2000 and for the periods from March 14, 2000 through  December 31, 2000, and
from  January 1, 2000  through  March 13, 2000 and as of and for the years ended
December  31,  1999 and 1998  have  been  derived  from  the  Company's  audited
historical consolidated financial statements.

<TABLE>
<CAPTION>
                                                                                         MEHC (PREDECESSOR)
                                                                                    ------------------------------------
                                                                    MARCH 14, 2000                       YEAR ENDED
                                         YEAR ENDED DECEMBER 31,        THROUGH     JANUARY 1, 2000     DECEMBER 31,
                                         -----------------------      DECEMBER 31,     THROUGH       -------------------
                                          2002(1)       2001(2)        2000(3)      MARCH 13, 2000   1999 (4)   1998 (5)
                                         ---------     ---------     ------------   ---------------  -------------------
<S>                                      <C>           <C>            <C>               <C>          <C>        <C>
Statement of Operations Data:
Operating revenue ..................     $ 4,794.0     $ 4,696.8      $ 3,918.1         $1,056.4     $ 4,086.6  $2,475.2
Total revenue ......................       4,968.1       4,973.0        4,013.0          1,075.8       4,368.5   2,602.7
Total costs and expenses ...........       4,325.0       4,469.1        3,793.8            984.7       4,011.5   2,330.7
Income before provision
for income taxes ...................         643.1         503.9          219.2             91.2         357.1     272.1
Minority interest ..................         163.5         106.5           84.7              8.9          46.9      41.3
Income before extraordinary item
and change in accounting
principle ..........................         380.0         147.3           81.3             51.3         216.7        --
Extraordinary item,
net of tax .........................            --            --             --               --         (49.4)     (7.1)
Cumulative effect of
change in accounting
principle, net of tax ..............            --          (4.6)            --               --            --      (3.4)
Net income .........................         380.0         142.7           81.3             51.3         167.2     127.0

BALANCE SHEET DATA:
Total assets .......................     $18,016.5     $12,626.7      $11,610.9              N/A     $10,766.4  $9,103.5
Total liabilities ..................      13,478.0       9,778.8        8,911.3              N/A       8,987.9   7,598.0
Company-obligated mandatory
redeemable preferred securities of
subsidiary trusts ..................       2,063.4         788.2          786.5              N/A         450.0     553.9
Subsidiary-obligated mandatorily
redeemable preferred securities
of subsidiary trusts ...............            --         100.0          100.0              N/A         101.6        --
Preferred securities of subsidiaries          93.3         121.2          145.7              N/A         146.6      66.0
Total stockholders' equity .........       2,294.3       1,708.2        1,576.4              N/A         994.6     827.1
</TABLE>



(1)  Reflects  the  acquisitions  of Kern River on March 27,  2002 and  Northern
     Natural Gas on August 16, 2002.

(2)  Reflects the Yorkshire Swap on September 21, 2001.

(3)  Reflects the Teton Transaction on March 14, 2000.

(4)  Reflects  the  MidAmerican  Energy  acquisition  on  March  12,  1999,  the
     disposition of Coso Joint Ventures on February 26, 1999, the disposition of
     50% ownership interest in CE Generation on March 3, 1999, $81.5 million for
     non-recurring  Indonesia  gain on  settlement,  gains on sales of McLeodUSA
     Class A common stock and qualified facilities, CE Electric UK restructuring
     charges and Teton Transaction costs.

(5)  Reflects the acquisition of Kiewit Diversified Group on January 2, 1998.

                                      -36-
<PAGE>

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS.

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

GENERAL

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

As a result of the recent  acquisitions of Kern River and Northern  Natural Gas,
the Yorkshire Swap, and the acquisition by a private investor group on March 14,
2000, the Company's future results will differ from its historical results.

2002 ACQUISITIONS

Kern River
----------

In March 2002, the Company  acquired Kern River for $419.7 million,  net of cash
acquired of $7.7  million and a working  capital  adjustment.  Kern River owns a
926-mile  interstate  natural gas pipeline  extending from Wyoming to markets in
California,  Nevada  and Utah and  accesses  natural  gas  supplies  from  large
producing  regions in the Rocky  Mountains and Canada.  In  connection  with the
acquisition   of  Kern  River,   the  Company   issued  $323.0  million  of  11%
Company-obligated  mandatorily  redeemable  preferred  securities  of subsidiary
trust due March 12, 2012 with scheduled principal payments beginning in 2005 and
$127.0 million of no par, zero coupon  convertible  preferred stock to Berkshire
Hathaway Inc.("Berkshire Hathaway").

Northern Natural Gas
--------------------

In August 2002, the Company  acquired  Northern  Natural Gas for $882.7 million,
net of cash acquired of $1.4 million and a working capital adjustment.  Northern
Natural Gas owns a 16,600-mile  interstate  natural gas pipeline  extending from
southwest  Texas to the upper Midwest  region of the United States with a design
capacity of 4.4 Bcf of natural gas per day.  Northern  Natural Gas also operates
three natural gas storage facilities and two liquefied natural gas peaking units
with a total storage capacity of 59 Bcf and peak delivery capability of over 1.3
Bcf of natural gas per day.  Northern  Natural Gas  accesses  natural gas supply
from many of the larger producing regions in North America,  including the Rocky
Mountains,  Hugoton, Permian, Anadarko and Western Canadian basins. The pipeline
system   provides    transportation   and   storage   services   to   utilities,
municipalities,  other  pipeline  companies,  gas marketers and  industrial  and
commercial users. The Company used the proceeds from a $950.0 million investment
in its subsidiary trust's preferred  securities by Berkshire Hathaway to finance
the acquisition.

HomeServices' 2002 Acquisitions
-------------------------------

In 2002,  HomeServices  separately  acquired three real estate  companies for an
aggregate purchase price of approximately  $106.1 million, net of cash acquired,
plus working capital and certain other adjustments.  For the year ended December
31, 2001,  these real estate  companies  had combined  revenue of  approximately
$356.0  million  on 42,000  closed  sides  representing  $13.7  billion of sales
volume.  Additionally,  HomeServices  is obligated  to pay a maximum  earnout of
$18.5 million based on 2002 financial performance measures. These purchases were
financed using HomeServices'  internally generated cash flows,  revolving credit
facility  and  $40.0  million  from  the  Company,   which  was  contributed  to
HomeServices as equity.

                                      -37-
<PAGE>

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements and related documents in conformity with
accounting  principles  generally  accepted  in the  United  States  of  America
requires management to make judgments, assumptions and estimates that affect the
amounts  reported in the  consolidated  financial  statements  and  accompanying
notes.  Note 2 to the  consolidated  financial  statements  for the  year  ended
December  31, 2002  included in this annual  report  describes  the  significant
accounting  policies and methods  used in the  preparation  of the  consolidated
financial statements. Estimates are used for, but not limited to, the accounting
for  revenue,  the  effects  of  certain  types  of  regulation,  impairment  of
long-lived assets, and contingent liabilities.  Actual results could differ from
these  estimates.  The  following  critical  accounting  policies  are  impacted
significantly by judgments, assumptions and estimates used in the preparation of
the consolidated financial statements.

Accounting for the Effects of Certain Types of Regulation
---------------------------------------------------------

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

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

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

Impairment of Long-Lived Assets
-------------------------------

The Company's  long-lived  assets consist  primarily of  properties,  plants and
equipment.  Depreciation  is computed  using the  straight-line  method based on
economic lives or regulatory mandated recovery periods. The Company believes the
useful lives assigned to the depreciable assets, which generally range from 3 to
87 years, are reasonable.

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

The estimate of cash flows arising from future use of the asset that are used in
the  impairment  analysis  requires  judgment  regarding  what the Company would
expect to recover from future use of the asset.  Any changes in the estimates of
cash flows  arising  from future use of the asset or the  residual  value of the
asset on disposal based on changes in the market conditions,  changes in the use
of the asset,  management's  plans, the  determination of the useful life of the
asset and  technology  changes in the industry  could  significantly  change the
calculation  of the fair  value  or  recoverable  amount  of the  asset  and the
resulting  impairment  loss,  which  could  significantly  affect the results of
operations.  The determination of whether impairment has occurred is based on an
estimate of undiscounted  cash flows  attributable to the assets, as compared to
the  carrying  value  of  the  assets.  An  impairment  analysis  of  generating
facilities  requires  estimates of possible  future market prices,  load growth,
competition and many other factors over the lives of the facilities. A resulting
impairment loss is highly dependent on these underlying assumptions.

                                      -38-
<PAGE>

Contingent Liabilities
----------------------

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

Revenue Recognition
-------------------

Revenue is recorded based upon services rendered and electricity,  gas and steam
delivered, distributed or supplied to the end of the period. The Company records
unbilled revenue representing the estimated amounts customers will be billed for
services  rendered between the meter reading dates in a particular month and the
end of that month.  The unbilled  revenue  estimate is reversed in the following
month.  To the extent  the  estimated  amount  differs  from the  actual  amount
subsequently billed, revenue will be affected.

Where there is an over recovery of United Kingdom distribution  business revenue
against  the  maximum  regulated  amount,  revenue  is  deferred  in  an  amount
equivalent to the over recovered  amount.  The deferred  amount is deducted from
revenue and included in other liabilities.  Where there is an under recovery, no
anticipation of any potential future recovery is made.

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

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

RESULTS OF  OPERATIONS  FOR THE YEAR ENDED  DECEMBER 31, 2002 AND THE YEAR ENDED
DECEMBER 31, 2001

Operating  revenue for the year ended December 31, 2002 increased  $97.2 million
or 2.1% to $4,794.0 million from $4,696.8 million for the same period in 2001.

CE Electric UK operating  revenue for the year ended December 31, 2002 decreased
$648.6  million or 44.9% to $795.4  million from  $1,444.0  million for the same
period  in  2001,  primarily  due to the  sale of the  supply  business  in 2001
partially offset by the acquisition of Yorkshire  Electric in September 2001 and
changes  in  the  exchange  rate.  CE  Electric  UK  distributed  41,157  GWh of
electricity  in the year ended  December 31, 2002,  compared  with 23,770 GWh of
electricity in the same period in 2001. The increase in electricity  distributed
is primarily due to the acquisition of Yorkshire distribution.

MidAmerican  Energy  operating  revenue  for the year ended  December  31,  2002
decreased  $147.8 million or 6.2% to $2,240.9  million from $2,388.7 million for
the same period in 2001.  MidAmerican Energy electric retail sales increased for
the year ended  December 31, 2002 from the same period in 2001 due  primarily to
higher temperatures in 2002,  primarily in the third quarter of 2002.  Regulated
and  non-regulated  gas revenue  decreased due to lower prices for gas purchased
passed directly to the customer.

Kern River operating revenue, from its date of acquisition,  was $127.3 million.
Kern River  transported  285,848,285  MMBtus during the period since the Company
acquired Kern River on March 27, 2002 through December 31, 2002.

Northern Natural Gas operating revenue, from its date of acquisition, was $176.9
million.  Northern Natural Gas transported  416,272,813 MMBtus since the Company
acquired Northern Natural Gas on August 16, 2002 through December 31, 2002.

                                      -39-
<PAGE>

CalEnergy  Generation - Domestic  operating  revenue for the year ended December
31, 2002  increased $1.2 million or 3.2% to $38.5 million from $37.3 million for
the same period in 2001.

CalEnergy Generation - Foreign operating revenue for the year ended December 31,
2002 increased $122.8 million or 60.3% to $326.3 million from $203.5 million for
the same period in 2001,  primarily due to commencement of commercial  operation
of the Casecnan Project in December 2001.

HomeServices  operating  revenue for the year ended  December 31, 2002 increased
$496.4  million or 77.3% to $1,138.3  million  from $641.9  million for the same
period in 2001,  primarily due to current year  acquisitions'  contributions  of
$431.5  million.  The remainder of  HomeServices'  increase was due to growth of
existing  companies of $105.3  million  partially  offset by a decrease of $40.4
million from a joint venture that was  consolidated in 2001 and is accounted for
under the equity method in 2002.

Income on equity investments for the year ended December 31, 2002 increased $0.9
million or 2.3% to $40.5 million from $39.6 million for the same period in 2001.
The increase was primarily due to $8.8 million income from a HomeServices' joint
venture which was fully  consolidated  in 2001 partially  offset by $7.9 million
lower  earnings  at CE  Generation  as a result of higher  earnings  from higher
energy prices in 2001.

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

Other income for the year ended  December 31, 2002  decreased  $134.7 million or
63.5% to $77.4  million from $212.1  million for the same period in 2001.  Other
income in 2002 resulted  primarily from the non-recurring gain on the sale of CE
Gas of $54.3  million  and equity  AFUDC at Kern River of $10.6  million.  These
items were offset,  in 2002,  by losses from the  write-down of  investments  at
MidAmerican  Energy of $21.9  million.  Other income in 2001  resulted  from the
non-recurring  gains  from the sales of  Northern  Electric's  supply  business,
Telephone Flat and Western States  Geothermal of $196.7  million,  $20.7 million
and $9.8 million,  respectively,  and a non-recurring  gain from the transfer of
Bali shares of $10.4 million.  These items were partially  offset, in 2001, by a
charge  related to the  impairment  of the  Company's  interest in Teeside Power
Limited ("TPL") of $58.8 million.

Cost of sales for the year ended December 31, 2002  decreased  $497.2 million or
21.2% to $1,844.0 million from $2,341.2 million for the same period in 2001.

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

MidAmerican  Energy cost of sales for the year ended December 31, 2002 decreased
$132.4  million or 11.8% to $988.9  million from  $1,121.3  million for the same
period in 2001,  primarily due to decreases in regulated and  non-regulated  gas
costs,  caused by lower volumes and prices,  partially  offset by an increase in
regulated  electric  costs  caused by higher  volumes,  partially  offset by the
restructuring of the Cooper Nuclear Station contract.

Northern  Natural Gas had cost of sales of $1.1 million since its acquisition on
August 16, 2002.

HomeServices cost of sales for the year ended December 31, 2002 increased $371.9
million or 94.0% to $767.6  million  from $395.7  million for the same period in
2001.  The  increase was  primarily  due to  acquisitions  during 2002 of $315.6
million,  and  higher  commission  expense  resulting  from  increased  sales at
existing  HomeServices  divisions,  partially  offset by $9.0 million of cost of
sales from a joint venture which had been  consolidated in 2001 and is accounted
for under the equity method in 2002.

Operating expenses for the year ended December 31, 2002 increased $168.8 million
or 14.3% to $1,345.2  million from $1,176.4 million for the same period in 2001.
The increase was primarily due to higher costs at  HomeServices of $99.1 million
as a result of  acquisitions,  operating  expenses  due to the  acquisitions  of
Northern  Natural Gas of $95.0 million and Kern River of $27.2 million and plant
operating expenses at the Zinc project and Casecnan of $33.9 million,  partially
offset by lower costs at  MidAmerican  Energy of $57.5 million  primarily due to
the  restructuring  of the Cooper  Nuclear  Station  contract  and lower  energy
efficiency  expenses  and lower costs at CE Electric UK of $28.5  million due to
the sale of the supply business.

                                      -40-
<PAGE>

Depreciation  and  amortization  for the year ended  December 31, 2002 decreased
$12.8 million or 2.4% to $525.9  million from $538.7 million for the same period
in 2001. The decrease was primarily due to discontinuance of amortizing goodwill
beginning  January 1, 2002 of $96.4 million,  partially offset by a full year of
operations at CE Casecnan of $22.0 million,  higher  depreciation at MidAmerican
Energy of $17.2 million  primarily due to higher Iowa revenue  sharing  accruals
and  a  change  in  the  estimated  useful  lives  of  electric  general  plant,
depreciation  expense due to the acquisitions of Kern River of $17.2 million and
Northern Natural Gas of $18.2 million and increased amortization at HomeServices
of $9.5 million primarily due to the amortization of the gross margin of pending
sales contracts related to acquisitions.

Interest expense, less amounts capitalized, for the year ended December 31, 2002
increased  $197.1 million or 47.7% to $609.9 million from $412.8 million for the
same period in 2001.  The increase was primarily due to the increase of interest
expense at CE Electric UK of $71.3 million predominantly due to the debt related
to the  Yorkshire  acquisition,  interest  expense  due to debt  related  to the
acquisitions  of Kern River and Northern  Natural Gas of $33.0 million and $23.0
million, respectively and the discontinuance of capitalizing interest related to
the Casecnan Project, the Cordova Project and the Zinc Recovery Project of $50.9
million,  $9.4 million and $5.3 million,  respectively,  all partially offset by
capitalized interest at Kern River of $14.0 million.

Tax expense for the year ended  December 31, 2002  decreased  $150.5  million or
60.2% to $99.6  million  from $250.1  million  for the same period in 2001.  The
decrease is due primarily to the tax expense related to the sale of the Northern
Electric supply business in September 2001, the release of the tax obligation of
$35.7  million  in  connection  with  the  execution  of the  TPL  restructuring
agreement  at CE Electric UK in 2002,  and the  recognition  of a tax benefit in
connection with the sale of the CE Gas assets in 2002.

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

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

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

The following is a discussion of the  historical  results of the Company for the
year ended December 31, 2001 and the period March 14, 2000 through  December 31,
2000,  and of its  predecessor  (referred  to as "MEHC  (Predecessor)")  for the
period January 1, 2000 through March 13, 2000.  Results for the Company  include
the  impact  of the  Teton  Transaction  beginning  March  14,  2000  which  are
predominately  the  minority  interest  costs on issuance  of  Company-obligated
mandatorily  redeemable  preferred  securities  of a  subsidiary  trust  and the
effects of purchase accounting,  including goodwill  amortization and fair value
adjustments to the carrying value of assets and liabilities.

Operating  revenue for the year ended December 31, 2001 decreased $277.7 million
or 5.6% to $4,696.8 million from $4,974.5 million for the same period in 2000.

MidAmerican  Energy  operating  revenue  for the year ended  December  31,  2001
increased  $72.4 million or 3.1% to $2,388.7  million from $2,316.3  million for
the same period in 2000.  MidAmerican Energy electric retail sales increased for
the year ended  December 31, 2001 from the same period in 2000 due to the warmer
temperatures  during the cooling season and an increase in  non-weather  related
sales.  Electric sales for resale increased for the year ended December 31, 2001
from the same  period in 2000 due to higher  production  at the  Cooper and Neal
power plants and favorable market  conditions.  Regulated and  non-regulated gas
supplied  increased due principally to growth in the  non-regulated  markets for
the year ended December 31, 2001 compared to the same period in 2000.

CE Electric UK operating  revenue for the year ended December 31, 2001 decreased
$553.9 million or 27.7% to $1,444.0  million from $1,997.9  million for the same
period in 2000,  primarily  due to the sale of the supply  business  in 2001 and
changes in foreign exchange rates. The decrease in electricity  supplied for the
year ended December 31, 2001 is due to

                                      -41-
<PAGE>

the sale of the  Northern  Electric  supply  business  in  September  2001.  The
increase in electricity  distributed for the year ended December 31, 2001 is due
to the addition of Yorkshire and changes in demand in the distribution area. The
decrease in gas  supplied in 2001 from 2000  reflects  the sale of the  Northern
Electric supply business.

The  remaining  increase  primarily  relates  to  the  increase  of  revenue  at
HomeServices  due to acquisitions and the inclusion of a joint venture which was
previously  accounted  for as an  equity  investment  and  the  commencement  of
operations of the Cordova Project in June 2001.

Income on equity investments for the year ended December 31, 2001 decreased $3.9
million or 9.0% to $39.6 million from $43.5 million for the same period in 2000.
The decrease was  primarily due to a joint  venture at  HomeServices  previously
accounted for as an equity investment that was fully consolidated in 2001.

Interest and dividend income for the year ended December 31, 2001 decreased $8.8
million or 26.3% to $24.6  million  from $33.4  million  for the same  period in
2000. The decrease was due primarily to decreased interest income at Casecnan as
funds previously invested were used for capital expenditures.

Other income for the year ended  December 31, 2001  increased  $174.6 million to
$212.1  million from $37.5 million for the same period in 2000. The increase was
primarily  due to  non-recurring  gains  from the sales of  Northern  Electric's
supply business,  Telephone Flat and Western States Geothermal recorded in 2001,
of  $196.7  million,  $20.7  million  and  $9.8  million,  respectively,  and  a
non-recurring  gain from the  transfer of Bali shares of $10.4  million in 2001.
These  items  were  partially  offset by a write down of the  investment  in TPL
during 2001 of $58.8 million.

Cost of sales for the year ended December 31, 2001  decreased  $428.0 million or
15.5% to $2,341.2 million from $2,769.2 million for the same period in 2000. The
decrease  relates  primarily to decreased cost of sales at CE Electric UK due to
the sale of the Northern  Electric supply business,  lower foreign exchange rate
and lower electricity volumes and prices,  partially offset by increased volumes
and prices for both regulated and non-regulated gas at MidAmerican  Energy,  and
acquisitions at HomeServices.

Operating  expenses for the year ended December 31, 2001 increased $45.0 million
or 4.0% to $1,176.4  million from $1,131.4  million for the same period in 2000.
The  increase  was  primarily  due  to  higher  costs  at  HomeServices  due  to
acquisitions and the inclusion of a joint venture which was previously accounted
for as an equity investment and higher costs at MidAmerican  Energy due to costs
related to Cooper, accounts receivable discounts and bad debts, partially offset
by lower costs at CE Electric UK due to the sale of the supply  business,  lower
pension costs and a lower  exchange  rate,  partially  offset by the addition of
Yorkshire.  In addition,  the Company  recorded  $7.6 million in the period from
January 1, 2000  through  March 13,  2000 which  represents  the costs  incurred
related to the Teton Transaction.

Depreciation  and  amortization  for the year ended  December 31, 2001 increased
$58.1 million or 12.1% to $538.7 million from $480.6 million for the same period
in 2000. This increase was due to higher  depreciation at MidAmerican Energy due
to  inclusion of Iowa revenue  sharing  accrual and an increase in  depreciation
rates  implemented in 2001 and amortization of the gross margin of pending sales
contracts  related to the HomeServices  acquisitions,  partially offset by lower
depreciation at CE Electric UK due to lower  amortization of operational  assets
and lower exchange rate, partially offset by the addition of Yorkshire.

Interest expense, less amounts capitalized, for the year ended December 31, 2001
increased  $15.6 million or 3.9% to $412.8  million from $397.2  million for the
same  period  in  2000.  This  increase  is due to  increased  interest  expense
associated with the debt acquired with Yorkshire and lower capitalized  interest
on the mineral extraction process, partially offset by lower average outstanding
debt balances and lower foreign exchange rates at CE Electric UK.

Tax expense for the year ended  December 31, 2001  increased  $165.8  million or
196.7% to $250.1  million  from $84.3  million for the same period in 2000.  The
increase is due primarily to the tax on the gain related to the sale of Northern
Electric supply business and higher pre-tax income.

Minority  interest and preferred  dividends for the year ended December 31, 2001
increased  $13.0  million or 13.9% to $106.5  million from $93.5 million for the
same  period  in  2000.  The  increase  is  primarily  due  to the  issuance  of
Company-obligated  mandatorily  redeemable  preferred  securities  of subsidiary
trusts  relating to the Teton  Transaction  and increased  minority  interest at
HomeServices related to certain mortgage and title joint ventures.

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

                                      -42-
<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

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

The  Company's  cash and cash  equivalents  were $844.4  million at December 31,
2002, compared $386.7 million at December 31, 2001. Each of the Company's direct
or indirect  subsidiaries is organized as a legal entity separate and apart from
the  Company  and  its  other  subsidiaries.   Pursuant  to  separate  financing
agreements at each  subsidiary,  the assets of each subsidiary may be pledged or
encumbered to support or otherwise provide the security for their own project or
subsidiary  debt.  It should not be assumed that any asset of any  subsidiary of
the Company will be available to satisfy the  obligations  of the Company or any
of its other subsidiaries;  provided,  however,  that unrestricted cash or other
assets which are available for  distribution  may, subject to applicable law and
the terms of financing arrangements for such parties, be advanced,  loaned, paid
as  dividends  or  otherwise  distributed  or  contributed  to  the  Company  or
affiliates thereof.

The Company  generated cash flows from operations of $757.7 million for the year
ended  December 31, 2002,  compared  with $847.0  million for the same period in
2001.  The decrease was  primarily  due to timing of changes in working  capital
activities,  partially  offset by  positive  impacts of the Kern River, Northern
Natural Gas and real estate companies acquisitions.

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

In addition,  the Company recorded separately restricted cash and investments of
$58.7  million and $54.8  million at December 31,  2002,  and December 31, 2001,
respectively.  The restricted cash balance as of December 31, 2002, is comprised
primarily of amounts deposited in restricted accounts which are reserved for the
service of debt obligations.

Kern River
----------

The Company  paid $419.7  million,  net of cash  acquired of $7.7  million and a
working  capital  adjustment,  for  Kern  River's  gas  pipeline  business.  The
acquisition  has been  accounted  for as a purchase  business  combination.  The
Company is in the process of completing  the allocation of the purchase price to
the assets and  liabilities  acquired.  The results of operations for Kern River
are included in the Company's results beginning March 27, 2002.

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

Northern Natural Gas
--------------------

The Company paid $882.7  million for Northern  Natural Gas, net of cash acquired
of  $1.4  million  and  a  working  capital  adjustment.  At  the  time  of  the
acquisition,  Northern Natural Gas had $950.0 million of debt  outstanding.  The
acquisition  has been  accounted  for as a purchase  business  combination.  The
Company is in the process of completing  the allocation of the purchase price to
the assets and  liabilities  acquired.  The results of  operations  for Northern
Natural Gas are included in the Company's results beginning August 16, 2002.

In connection with the  acquisition of Northern  Natural Gas, the Company issued
$950.0  million  of  11%  Company-obligated   mandatorily  redeemable  preferred
securities of subsidiary  trust due August 31, 2011,  with  scheduled  principal
payments beginning in 2003, to Berkshire Hathaway.

                                      -43-
<PAGE>

HomeServices' 2002 Acquisitions
---------------------------------------

In 2002,  HomeServices  separately  acquired three real estate  companies for an
aggregate purchase price of approximately  $106.1 million, net of cash acquired,
plus working capital and certain other adjustments.  For the year ended December
31, 2001,  these real estate  companies  had combined  revenue of  approximately
$356.0  million  on 42,000  closed  sides  representing  $13.7  billion of sales
volume.  Additionally,  HomeServices  is obligated  to pay a maximum  earnout of
$18.5 million based on 2002 financial performance measures. These purchases were
financed using HomeServices'  internally generated cash flows,  revolving credit
facility  and  $40.0  million  from  the  Company,   which  was  contributed  to
HomeServices as equity.

Williams' Company Preferred Stock
---------------------------------

On March 27, 2002, a newly formed  subsidiary of the Company,  MEHC  Investments
Inc.,  invested  $275.0  million in Williams  in  exchange  for shares of 9 7/8%
cumulative  convertible  preferred  stock of Williams.  In connection  with this
investment, the Company issued $275.0 million of no par, zero coupon convertible
preferred  stock to Berkshire  Hathaway.  Dividends on the  Williams'  preferred
stock are scheduled to be received quarterly, which commenced July 1, 2002. This
investment  is  accounted  for  under  the cost  method.  Since the date of this
investment,  there  have been  public  announcements  that  Williams'  financial
condition  has  deteriorated  as a  result  of,  among  other  factors,  reduced
liquidity.  The Company had not recorded an impairment on this  investment as of
December 31, 2002, and is monitoring the situation.

Yorkshire
---------

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

CE Gas Disposal
---------------

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

Kern River's 2003 Expansion Project
-----------------------------------

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

The 2003 Expansion  Project  includes the  construction  of three new compressor
stations and the installation of additional  compression and other modifications
at six existing  facilities.  When completed,  the Kern River system will have a
summer day design  capacity  of  approximately  1.73 Bcf per day, an increase of
approximately 886 mmcf per day.

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

The 2003 Expansion Project is being financed with approximately 70% debt and 30%
equity, consistent with Kern River's original capital structure, the application
for FERC approval of the 2003 Expansion Project and the limitations contained in
the indenture for Kern River's  existing secured senior notes. On June 21, 2002,
Kern River entered into an $875 million

                                      -44-
<PAGE>

credit facility to fund a portion of the costs of the 2003 Expansion Project and
the Company  issued a completion  guarantee  in favor of the lenders  under that
credit facility.

Construction is being  initially  funded with the proceeds of the $875.0 million
credit facility. The remaining approximately 30% of the capitalized costs of the
2003 Expansion Project is being funded with equity from the Company.  The credit
facility is structured as a two-year  construction  facility  followed by a term
loan with a final  maturity  15 years  after  completion  of the 2003  Expansion
Project.  However,  Kern River presently  intends to refinance the  construction
financing facility through a bond offering or other capital markets  transaction
following  completion of the 2003 Expansion Project.  Prior to completion of the
2003 Expansion Project, the holders of the construction  financing facility will
have limited  recourse to Kern River and its assets and cash flow, and will have
recourse  to the  Company's  completion  guarantee  described  below.  Following
completion  of the 2003  Expansion  Project,  until  such time as the Kern River
construction   financing   facility  is   refinanced,   the  lenders  under  the
construction financing facility will share equally and ratably with the existing
holders of Kern River's  senior Notes in all of the  collateral  pledged to such
Senior Note holders.

Pursuant  to MEHC's  completion  guarantee,  the  Company  has  guaranteed  that
"completion"  of the  2003  Expansion  Project  will  occur  on or  prior to the
earliest of any  abandonment  by Kern River of the project,  the  occurrence  of
certain other acceleration events and June 30, 2004. The potential  acceleration
events  include any  downgrading  of the  Company's  public debt rating to below
investment  grade by either  Standard  & Poor's  ("S&P")  or  Moody's  Investors
Service Inc. unless a satisfactory  substitute  guarantor  assumes the Company's
obligations  under  the  completion  guarantee  within  60 days  after  any such
downgrade;  Berkshire  Hathaway  ceasing  to  own at  least  a  majority  of the
outstanding capital stock of the Company;  and certain other customary events of
default by the Company. In the completion guarantee, the Company has also agreed
to cause capital  contributions to be made to Kern River in a minimum  aggregate
amount of at least $375.0  million by June 30, 2004 or upon any earlier event of
abandonment of the project. For purposes of the Company's completion  guarantee,
the term  "completion"  is  defined  in the Kern  River  construction  financing
agreement to mean  satisfaction of a number of conditions,  the most significant
of  which  include  the  requirements   that  the  2003  Expansion   Project  be
substantially complete and operable and able to permit Kern River to perform its
obligations  under  all  of  the  long-term  firm  gas  transportation   service
agreements entered into in connection with the 2003 Expansion Project;  that the
shippers under such  agreements  shall have begun to incur the obligation to pay
reservation fees thereunder;  and that the FERC shall have authorized Kern River
to begin collecting rates under its tariff and its shipper agreements;  provided
that the 2003 Expansion  Project shall still be deemed to have been completed if
it is less than  substantially  complete but it demonstrates at least 80% design
capacity and Kern River's debt service  coverage ratios as defined in its Senior
Notes  indenture  are not less  than  1:55 to 1:0.  There  are a number of other
conditions  to  completion,   including  requirements  that  all  conditions  to
completion of the expansion  contained in Kern River's Senior Notes indenture be
satisfied and all of Kern River's  obligations under its construction  financing
agreement  then share pari passu in all  collateral  available  to Kern  River's
senior secured  noteholders.  The Company's completion guarantee shall terminate
upon the earlier of  completion  of the 2003  Expansion  Project or repayment in
full of all obligations under the Kern River credit facility.

MidAmerican Energy Operating Projects and Construction and Development Costs
----------------------------------------------------------------------------

MidAmerican   Energy's   primary  need  for  capital  is  utility   construction
expenditures.  For the  year  ended  December  31,  2002,  utility  construction
expenditures  totaled $357  million,  including  allowance for funds used during
construction,  or capitalized  financing  costs, and Quad Cities Station nuclear
fuel purchases.

Forecasted utility construction expenditures, including allowance for funds used
during  construction,  are $368 million for 2003. Capital  expenditure needs are
reviewed  regularly by management  and may change  significantly  as a result of
such reviews.

Through 2010,  MidAmerican  Energy plans to develop and construct three electric
generating  projects in Iowa.  The projects  would provide  service to regulated
retail electricity customers and, subject to regulatory  approvals,  be included
in regulated rate base in Iowa,  Illinois and South Dakota.  Wholesale sales may
also be made from the plants to the extent the power is not needed for regulated
retail service.  MidAmerican Energy expects to invest approximately $1.6 billion
in the three projects, including the cost of related transmission facilities and
allowance  for funds used during  construction.  The three  projects may provide
approximately  1,285 MW of generating  capacity for MidAmerican Energy depending
on management's on-going assessment of energy needs and related factors.

The  first  project  is a  500-MW  (based  on  expected  accreditation)  natural
gas-fired   combined  cycle  unit  with  an  estimated  cost  of  $415  million.
MidAmerican Energy will own 100% of the plant and operate it. MidAmerican Energy
has received a  certificate  from the IUB  allowing it to  construct  the plant.
Also,  on May 29, 2002,  the IUB issued an order that  provides  the

                                      -45-
<PAGE>

ratemaking  principles  for the  gas-fired  plant.  As a result  of that  order,
MidAmerican  Energy is proceeding with the  construction of the plant. The plant
will be operated in simple cycle mode during 2003 and 2004,  resulting in 310 MW
of accredited capacity.  The combined cycle operation is expected to commence in
2005.

The second project is currently under development and is expected to be a 790-MW
(based on expected accreditation)  super-critical-temperature,  coal-fired plant
fueled with low-sulfur coal. If constructed, MidAmerican Energy will operate the
plant  and  expects  to  own  approximately  475  MW of  the  plant.  Municipal,
cooperative  and  public  power  utilities  will own the  remainder,  which is a
typical ownership arrangement for large base-load plants in Iowa. On January 23,
2003,  MidAmerican  Energy  received  an  order  approving  the  issuance  of  a
certificate from the IUB allowing it to construct the plant.  MidAmerican Energy
has made a filing with the IUB for approval of ratemaking  principles pertaining
to this  second  plant.  Continued  development  of this  plant  is  subject  to
obtaining  environmental and other required permits, as well as receiving orders
from the IUB approving  construction of the associated  transmission  facilities
and  establishing  ratemaking  principles  which are satisfactory to MidAmerican
Energy.

The third  project is  currently  under  development  and is expected to be wind
power facilities totaling 310 MW (nameplate rating). If constructed, MidAmerican
Energy  will own and  operate  these  facilities,  which  are  expected  to cost
approximately $323 million, plus associated transmission facilities. MidAmerican
Energy's plan to construct the wind project is in conjunction  with a settlement
proposal to extend  through  December  31, 2010, a rate freeze that is currently
scheduled  to  expire  at the end of  2005.  The  proposed  settlement  requires
enactment of Iowa legislation and is subject to approval by the IUB.

Development Activity
--------------------

Fox is  exploring  the  development  of a 635 net MW gas fired power  generating
facility in Kaukanna, Outagamie County, Wisconsin. A subsidiary of TransAlta has
agreed to participate  in the  development of this project at a level of 50% and
has an option to own 50% of the  project.  Obsidian is  developing  a 185 net MW
geothermal  facility in  Imperial  Valley,  California,  known as Salton Sea VI.
TransAlta has elected to  participate  in the ownership and  development of this
project at a level of 50%.

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

Debt Issuances and Redemptions
------------------------------

On  February  8,  2002,  MidAmerican  Energy  issued  $400.0  million  of  6.75%
medium-term notes due in 2031. The proceeds were used to refinance existing debt
and preferred  securities and for other corporate  purposes.  On March 11, 2002,
MidAmerican  Energy  redeemed  all  $100.0  million  of  its  7.98%  MidAmerican
Energy-obligated  preferred  securities  of a  subsidiary  trust  at 100% of the
principal amount plus accrued interest.

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

On June 21,  2002,  Kern  River  closed on a bank loan  facility  providing  for
aggregate  loans of up to $875.0 million to be used for the  construction of the
Kern River 2003 Expansion  Project.  The facility,  which matures 15 years after
the 2003 Expansion  Project  commences  operation,  has a variable interest rate
which  increases  over the term of the facility  from 1.375% to 4.5% over LIBOR.
Kern River had drawn $789.9 million on this facility as of December 31, 2002. In
connection with this facility, the Company guaranteed the completion of the 2003
Expansion Project as previously discussed.

On October 4, 2002, the Company issued $200.0 million of 4.625% Senior Notes due
in 2007 and $500.0  million of 5.875% Senior Notes due in 2012. The proceeds are
being  used  for  general  corporate  purposes  including  reducing   short-term
obligations,  to make a $150.0 million equity  contribution to Northern  Natural
Gas, and to make funds available to Kern River for its 2003 Expansion Project.

                                      -46-
<PAGE>

On October 15, 2002, Northern Natural Gas issued $300.0 million of 5.375% Senior
Notes  due  in  2012.  The  proceeds,  along  with  the  $150.0  million  equity
contribution  from  the  Company,  were  used  to  refinance  a  $450.0  million
short-term debt obligation.

On March 1, 2001,  MidAmerican  Funding, LLC ("MidAmerican  Funding"),  a wholly
owned subsidiary of the Company and MidAmerican Energy's parent company, retired
$200.0  million  of 5.85%  senior  secured  notes due 2001.  On March 19,  2001,
MidAmerican  Funding  issued  $200.0  million of 6.75% senior  secured notes due
March 1, 2011.

On  January  14,  2003,  MidAmerican  Energy  issued  $275.0  million  of 5.125%
medium-term  notes due in 2013. The proceeds will be used to refinance  existing
debt, support utility construction expenditures and other corporate purposes.

OBLIGATIONS AND COMMITMENTS

The Company has  contractual  obligations  and commercial  commitments  that may
affect its financial condition.  Contractual obligations to make future payments
arise from  parent  company and  subsidiary  long-term  debt and notes  payable,
preferred  equity  securities,  operating  leases  and power  and fuel  purchase
contracts.  Other  obligations  arise from unused lines of credit and letters of
credit.  Material  obligations  as of  December  31,  2002  are as  follows  (in
thousands):
<TABLE>
<CAPTION>
                                                                     PAYMENTS DUE BY PERIOD
                                                      -------------------------------------------------------
                                                                  LESS THAN     2-3         4-5      AFTER 5
Contractual Cash Obligations:                            TOTAL      1 YEAR      YEARS       YEARS      YEARS
                                                       ---------  --------    --------    --------   --------
<S>                                                    <C>          <C>       <C>         <C>         <C>
Parent company long-term debt (1) .................    $ 2,539.5    $215.0    $  260.0    $  550.0    $1,514.5
Subsidiary and project debt (1) ...................      7,332.3     255.2       847.2       587.2     5,642.7
Company-obligated mandatorily redeemable
  Preferred securities of subsidiary trusts .......      2,063.4     150.0       288.5       468.0     1,156.9
Mandatorily redeemable preferred securities
  of subsidiaries .................................         93.3      93.3          --          --          --
Coal, electricity and natural gas contract
  commitments (2) .................................        493.1     168.5       229.5        32.9        62.2
Operating leases (2) ..............................        293.2      60.8        85.4        60.3        86.7
                                                       ---------    ------    --------    --------    --------
  Total contractual cash obligations ..............    $12,814.8    $942.8    $1,710.6    $1,698.4    $8,463.0
                                                       =========    ======    ========    ========    ========
</TABLE>
<TABLE>
<CAPTION>

                                                             COMMITMENT EXPIRATION PER PERIOD
                                                      ---------------------------------------------
                                                                 LESS THAN     2-3         4-5      AFTER 5
Other Commercial Commitments:                            TOTAL     1 YEAR      YEARS       YEARS      YEARS
                                                       ---------  --------    --------    --------   --------
<S>                                                    <C>          <C>       <C>         <C>         <C>
Unused parent company revolving lines of credit ...    $   352.3    $352.3    $     --    $     --    $     --
Parent company letters of credit ..................         47.7        --        47.7          --          --
Unused subsidiaries lines of credit ...............        350.0     249.7       100.3          --          --
Parent company guarantee of subsidiary debt .......        174.8       1.4         3.6         2.9       166.9
Subsidiary lines of credit from parent company ....         10.0        --          --          --        10.0
                                                       ---------    ------    --------    --------    --------
   Total other commercial commitments .............    $   934.8    $603.4    $  151.6    $    2.9    $  176.9
                                                       =========    ======    ========    ========    ========
</TABLE>

     (1)  Excludes certain unamortized debt premiums and discounts

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

In addition to amounts in the table above,  the unused portion of the Kern River
Construction Financing Facility is $85.1 million.

As of December 31, 2002,  Northern  Natural Gas had $52.0 million of obligations
to deliver 12.2 Bcf of natural gas in 2003. The  obligations  are revalued based
on market  prices  for  natural  gas,  with  changes  in value  included  in the
statement of operations.  In 2002, Northern Natural Gas entered into natural gas
commodity  price  swaps and index basis swaps to  effectively  fix the  deferred
obligation balance. These swaps have a net receivable balance of $3.4 million at
December 31, 2002.  The swaps are  revalued  based on market  prices for natural
gas, with changes in value included in the statement of  operations.  Therefore,
any further changes in the market value of the deferred obligations are expected
to be offset by a corresponding  change in the opposite  direction in the market
value of the swaps.  However,  at December 31, 2002,  Northern Natural Gas had a
$10.4 million receivable position with a third party energy marketer relating to
these swaps. Since the date of entering into these swaps, there have been public
announcements that this third party's financial  condition has deteriorated as a
result of,  among

                                      -47-
<PAGE>

other  factors,   reduced   liquidity.   This   receivable   would  increase  by
approximately  $12.2  million if the price curve of natural gas were to increase
by $1/MMBtu  from levels at December 31,  2002.  The Company has not recorded an
allowance on this  receivable  as of December 31, 2002,  and is  monitoring  the
situation.

OFF-BALANCE SHEET ARRANGEMENTS

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

As of December 31, 2002, the Company's investments which are accounted for under
the equity method had an aggregate $1,023.6 million of debt and $43.7 million in
outstanding  letters of credit. As of December 31, 2002, the Company's  pro-rata
share of the debt was $507.6 million and was non-recourse to the Company, except
for $137.8  million of such debt which the Company has  guaranteed on the Salton
Sea Funding Series F Bonds and which was included in the Company's  consolidated
balance  sheet  at  December  31,  2002.  The  Company's  pro-rata  share of the
outstanding  letters of credit was $21.9  million as of December 31,  2002.  The
Company is generally  not required to support the debt  service  obligations  of
these investments. However, default with respect to this non-recourse debt could
result in a loss of invested equity.

NEW ACCOUNTING PRONOUNCEMENTS

In August 2001, the FASB issued SFAS No. 143,  "Accounting for Asset  Retirement
Obligations"  ("SFAS 143").  This statement  provides  accounting and disclosure
requirements for retirement obligations associated with long-lived assets and is
effective  January 1, 2003.  This  statement  requires that the present value of
retirement  costs for which the  Company has a legal  obligation  be recorded as
liabilities  with an equivalent  amount added to the asset cost and  depreciated
over an appropriate period. The liability is then accreted over time by applying
an interest  method of allocation  to the  liability.  Cumulative  accretion and
accumulated  depreciation  will be recognized  for the time period from the date
the liability  would have been  recognized  had the provisions of this statement
been in effect, to the date of adoption of this statement. The cumulative effect
of initially  applying  this  statement is  recognized as a change in accounting
principle.  The Company and its unconsolidated  subsidiary used an expected cash
flow approach to measure the obligations and adopted the statement as of January
1, 2003.

The  Company's  initial  review  of  its  regulated  entities  identified  legal
retirement  obligations for nuclear  decommissioning,  wet and dry ash landfills
and offshore  and minor  lateral  pipeline  facilities.  The Company  expects to
record approximately $290.0 million of asset retirement obligation  liabilities,
approximately  $265.0 million of which pertains to obligations  associated  with
the  decommissioning  of the Quad Cities nuclear  station.  The adoption of this
statement is not  expected to have a material  impact on the  operations  of the
regulated   entities,   as  the  effects  are  expected  to  be  offset  by  the
establishment  of regulatory  assets,  totaling  approximately  $115.0  million,
pursuant to SFAS 71.

In addition,  one of the Company's  unconsolidated  subsidiaries  has identified
legal  retirement  obligations  for landfill and plant  abandonment  costs.  The
Company's share of this adoption is expected to total $1.1 million, net of tax.

In August 2001, the FASB issued SFAS No. 144,  "Accounting for the Impairment or
Disposal of Long-Lived  Assets" ("SFAS 144").  SFAS 144 provides new guidance on
the recognition of impairment losses on long-lived assets to be held and used or
to be  disposed  of and also  broadens  the  definition  of what  constitutes  a
discontinued operation and how the results of a discontinued operation are to be
measured and presented. SFAS 144 supercedes SFAS No. 121 and APB Opinion No. 30,
while retaining many of the  requirements  of these two  statements.  Under SFAS
144,  assets held for sale that are a component of an entity will be included in
discontinued  operations if the  operations  and cash flows will be or have been
eliminated  from the  ongoing  operations  of the entity and the entity will not
have any  significant  continuing  involvement in the operations  prospectively.
SFAS 144 did not  materially  change the methods  used by the Company to measure
impairment   losses  on  long-lived   assets  but  may  result  in  more  future
dispositions  being reported as discontinued  operations  than would  previously
have been permitted. The Company adopted SFAS 144 on January 1, 2002.

In April 2002, the FASB issued SFAS No. 145,  "Rescission of FASB Statements No.
4, 44, and 64,  Amendment of FASB  Statement No. 13, and Technical  Corrections"
("SFAS  145").  SFAS  145  eliminates  extraordinary  accounting  treatment  for
reporting  gains or losses on debt  extinguishment,  and amends  other  existing
authoritative  pronouncements  to make various  technical  corrections,  clarify
meanings,  or  describe  their  applicability  under  changed  conditions.   The
provisions  of SFAS 145 related to the  rescission  of FASB  Statement No. 4 are
applicable in fiscal years beginning after

                                      -48-
<PAGE>

May 15, 2002, the provisions  related to FASB Statement No. 13 are effective for
transactions  occurring  after  May 15,  2002,  and  all  other  provisions  are
effective for  financial  statements  issued on or after May 15, 2002;  however,
early application is encouraged.  Debt extinguishments reported as extraordinary
items prior to scheduled or early adoption of SFAS 145 would be  reclassified in
most cases following adoption.  The Company does not expect the adoption of SFAS
145 to have a material effect on its financial position,  results of operations,
or cash flows.

In June 2002,  the FASB issued SFAS No. 146,  "Accounting  for Costs  Associated
with Exit or Disposal  Activities"  ("SFAS 146").  SFAS 146 nullifies EITF Issue
No. 94-3,  "Liability  Recognition for Certain Employee Termination Benefits and
Other  Costs  to  Exit  an  Activity  (including  Certain  Costs  Incurred  in a
Restructuring)"  ("EITF 94-3").  The principal  difference  between SFAS 146 and
EITF 94-3 relates to the  requirements  for recognition of a liability for costs
associated with an exit or disposal activity. SFAS 146 requires that a liability
be recognized for a cost associated with an exit or disposal activity when it is
incurred. A liability is incurred when a transaction or event occurs that leaves
an entity little or no discretion to avoid the future  transfer or use of assets
to settle  the  liability.  Under EITF 94-3,  a  liability  for an exit cost was
recognized  at the date of an entity's  commitment to an exit plan. In addition,
SFAS 146 also requires that a liability  for a cost  associated  with an exit or
disposal activity be recognized at its fair value when it is incurred.  SFAS 146
is effective for exit or disposal  activities  that are initiated after December
31,  2002  with  early  application  encouraged.  The  Company  will  apply  the
provisions  of SFAS  146 to all  exit or  disposal  activities  initiated  after
December 31, 2002.

In  November  2002,  the FASB issued FASB  Interpretation  No. 45,  "Guarantor's
Accounting  and  Disclosure  Requirements  for  Guarantees,  Including  Indirect
Guarantees  of  Indebtedness  of Others"  ("FIN  45").  FIN 45  requires  that a
liability be recorded in the guarantor's  balance sheet upon issuance of certain
guarantees.  In addition,  FIN 45 requires disclosures about the guarantees that
an entity has issued.  The provision for initial  recognition and measurement of
the  liability  will be applied on a prospective  basis to guarantees  issued or
modified  after  December  31, 2002.  The  disclosure  provisions  of FIN 45 are
effective for financial  statements  of interim or annual  periods  ending after
December 15, 2002.  The Company does not expect the adoption of FIN 45 to have a
material effect on its financial position, results of operations, or cash flows.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

At   December   31,   2002,   the  Company  had   fixed-rate   long-term   debt,
Company-obligated  mandatorily  redeemable  preferred  securities  of subsidiary
trusts, and subsidiary-obligated  mandatorily redeemable preferred securities of
subsidiary  trusts of $11,683.2  million in  principal  amount and having a fair
value of $12,188.8  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  $397.1  million if  interest  rates were to  increase by 10% from
their  levels at December 31,  2002.  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,  2002,  the Company had  floating-rate  obligations  of $425.1
million that expose the Company to the risk of increased interest expense in the
event of increases in  short-term  interest  rates.  These  obligations  are not
hedged. If the floating rates were to increase by 1% the Company's  consolidated
interest  expense  for  unhedged  floating-rate  obligations  would  increase by
approximately  $0.4 million each month in which such  increase  continued  based
upon December 31, 2002 principal balances.

                                      -49-
<PAGE>


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.



         Independent Auditors' Report.........................................51

         Consolidated Balance Sheets as of December 31, 2002 and 2001.........52

         Consolidated Statements of Operations
           for the  Years  Ended  December  31,  2002 and 2001 and for the
           periods from March 14, 2000 through December 31, 2000 and
           January 1, 2000 through March13, 2000..............................53

         Consolidated Statements of Stockholders' Equity
           for the Three Years Ended December 31, 2002, 2001 and 2000.........54

         Consolidated Statements of Cash Flows
           for the  Years  Ended  December  31,  2002 and 2001 and for the
           periods from March 14, 2000 through December 31, 2000 and
           January 1, 2000 through March13, 2000..............................55

         Notes to Consolidated Financial Statements...........................56


                                      -50-

<PAGE>


                          INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
MidAmerican Energy Holdings Company
Des Moines, Iowa

We have audited the  accompanying  consolidated  balance  sheets of  MidAmerican
Energy  Holdings  Company  (successor to  MidAmerican  Energy  Holdings  Company
(Predecessor),  referred  to as  "MEHC  (Predecessor)")  and  subsidiaries  (the
"Company")  as of December  31, 2002 and 2001 for the  Company,  and the related
consolidated statements of operations,  stockholders' equity, and cash flows for
the years  ended  December  31,  2002 and 2001 for the  Company,  for the period
January  1, 2000 to March 13,  2000 for MEHC  (Predecessor),  and for the period
March 14, 2000 to December  31, 2000 for the Company.  Our audits also  included
the  financial  statement  schedules  listed  in the  Index  at Item  15.  These
financial statements and financial statement schedules are the responsibility of
the Company's  management.  Our responsibility is to express an opinion on these
financial statements and financial statement schedules based on our audits.

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

In our opinion,  such consolidated  financial  statements present fairly, in all
material respects, the financial position of MidAmerican Energy Holdings Company
and  subsidiaries  as of December  31,  2002 and 2001,  and the results of their
operations and their cash flows for the above stated periods in conformity  with
accounting principles generally accepted in the United States of America.  Also,
in our opinion, such financial statement schedules,  when considered in relation
to the basic consolidated  financial statements taken as a whole, present fairly
in all material respects the information set forth therein.

As discussed in Note 2 to the  consolidated  financial  statements,  in 2002 the
Company changed its accounting  policy for goodwill and other intangible  assets
and in 2001 the  Company  changed is  accounting  policy for major  maintenance,
overhaul and well workover costs.

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP
Des Moines, Iowa
January 24, 2003

                                      -51-

<PAGE>
                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                           CONSOLIDATED BALANCE SHEETS
                             (Amounts in thousands)
<TABLE>
<CAPTION>
                                                                                              AS OF DECEMBER 31,
                                                                                        ----------------------------
                                                                                            2002              2001
                                                                                        ------------    ------------
                                     ASSETS
<S>                                                                                     <C>             <C>
Current assets:
  Cash and cash equivalents .........................................................   $    844,430    $    386,745
  Restricted cash and short-term investments ........................................         50,808          30,565
  Accounts receivable, net of allowance for doubtful accounts of $39,742 and $7,319 .        707,731         310,030
  Inventories .......................................................................        126,938         135,822
  Other current assets ..............................................................        212,888         106,124
                                                                                        ------------    ------------
Total current assets ................................................................      1,942,795         969,286
                                                                                        ------------    ------------
Properties, plants and equipment, net ...............................................      9,810,087       6,537,371
Excess of cost over fair value of net assets acquired ...............................      4,258,132       3,638,546
Regulatory assets ...................................................................        504,513         221,120
Other investments ...................................................................        446,732         174,185
Equity investments ..................................................................        273,707         261,432
Deferred charges and other assets ...................................................        780,489         824,712
                                                                                        ------------    ------------
TOTAL ASSETS ........................................................................   $ 18,016,455    $ 12,626,652
                                                                                        ============    ============

                      LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Accounts payable ..................................................................   $    462,960    $    266,027
  Accrued interest ..................................................................        192,015         130,569
  Accrued taxes .....................................................................         75,097          88,973
  Other accrued liabilities .........................................................        457,058         308,924
  Short-term debt ...................................................................         79,782         256,012
  Current portion of long-term debt .................................................        470,213         317,180
                                                                                        ------------    ------------
    Total current liabilities .......................................................      1,737,125       1,367,685
                                                                                        ------------    ------------
Other long-term accrued liabilities .................................................      1,100,917         537,495
Parent company debt .................................................................      2,324,456       1,834,498
Subsidiary and project debt .........................................................      7,077,087       4,754,811
Deferred income taxes ...............................................................      1,238,421       1,284,268
                                                                                        ------------    ------------
  Total liabilities .................................................................     13,478,006       9,778,757
                                                                                        ------------    ------------

Deferred income .....................................................................         80,078          85,917
Minority interest ...................................................................          7,351          44,477
Company-obligated mandatorily redeemable preferred securities of subsidiary trusts ..      2,063,412         788,151
Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts           --           100,000
Preferred securities of subsidiaries ................................................         93,325         121,183

Commitments and contingencies (Note 20)

Stockholders' equity:
Zero coupon convertible preferred stock - authorized 50,000 shares, no par value,
  41,263 and 34,563 shares outstanding at December 31, 2002 and 2001, respectively ..           --              --
Common stock - authorized 60,000 no par value; 9,281 shares issued
  and outstanding at December 31, 2002 and 2001 .....................................           --              --
Additional paid-in capital ..........................................................      1,956,509       1,553,073
Retained earnings ...................................................................        584,009         223,926
Accumulated other comprehensive loss, net ...........................................       (246,235)        (68,832)
                                                                                        ------------    ------------
  Total stockholders' equity ........................................................      2,294,283       1,708,167
                                                                                        ------------    ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ..........................................   $ 18,016,455    $ 12,626,652
                                                                                        ============    ============
</TABLE>
   The accompanying notes are an integral part of these financial statements.

                                      -52
<PAGE>
                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                             (Amounts in thousands)
<TABLE>
<CAPTION>

                                                                                                     MEHC
                                                                                                 (PREDECESSOR)
                                                  YEAR ENDED DECEMBER 31,      MARCH 14, 2000   JANUARY 1, 2000
                                                ----------------------------       THROUGH          THROUGH
                                                   2002             2001      DECEMBER 31, 2000  MARCH 13, 2000
                                                -----------      -----------  -----------------  --------------

<S>                                             <C>              <C>              <C>              <C>
REVENUE:
  Operating revenue .......................     $ 4,794,010      $ 4,696,781      $ 3,918,100      $ 1,056,365
  Income on equity investments ............          40,520           39,565           40,019            3,497
  Interest and dividend income ............          56,250           24,552           25,320            8,080
  Other income ............................          77,359          212,082           29,543            7,907
                                                -----------      -----------      -----------      -----------
    Total revenue .........................       4,968,139        4,972,980        4,012,982        1,075,849
                                                -----------      -----------      -----------      -----------
COSTS AND EXPENSES:
  Cost of sales ...........................       1,844,024        2,341,178        2,194,512          574,679
  Operating expense .......................       1,345,205        1,176,422          904,511          226,908
  Depreciation and amortization ...........         525,902          538,702          383,351           97,278
  Interest expense ........................         647,379          499,263          396,773          101,330
  Less interest capitalized ...............         (37,469)         (86,469)         (85,369)         (15,516)
                                                -----------      -----------      -----------      -----------
    Total costs and expenses ..............       4,325,041        4,469,096        3,793,778          984,679
                                                -----------      -----------      -----------      -----------
INCOME BEFORE PROVISION FOR INCOME TAXES ..         643,098          503,884          219,204           91,170
  Provision for income taxes ..............          99,588          250,064           53,277           31,008
                                                -----------      -----------      -----------      -----------
INCOME BEFORE MINORITY INTEREST AND
  PREFERRED DIVIDENDS .....................         543,510          253,820          165,927           60,162
  Minority interest and preferred dividends         163,467          106,547           84,670            8,850
                                                -----------      -----------      -----------      -----------
INCOME BEFORE CUMULATIVE EFFECT OF
  CHANGE IN ACCOUNTING PRINCIPLE ..........         380,043          147,273           81,257           51,312
Cumulative effect of change in accounting
  principle, net of tax (Note 2) ..........            --             (4,604)            --               --
                                                -----------      -----------      -----------      -----------
NET INCOME AVAILABLE TO COMMON
  AND PREFERRED STOCKHOLDERS ..............     $   380,043      $   142,669      $    81,257      $    51,312
                                                ===========      ===========      ===========      ===========
</TABLE>

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

                                      -53-
<PAGE>
                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                             (Amounts in thousands)
<TABLE>
<CAPTION>
                                                                                            ACCUMULATED
                                          OUTSTANDING             ADDITIONAL                  OTHER
                                            COMMON      COMMON     PAID-IN       RETAINED  COMPREHENSIVE   TREASURY
                                            SHARES      STOCK      CAPITAL       EARNINGS   INCOME(LOSS)     STOCK         TOTAL
                                          -----------   ------   ------------    ---------  ------------   --------     -----------
<S>              <C>                        <C>         <C>       <C>            <C>          <C>          <C>          <C>
Balance, January 1, 2000 .............      59,944      $  --     $ 1,249,079    $ 507,726    $ (12,029)   $(750,188)   $   994,588

Net income January 1, 2000
  through March 13, 2000 .............        --           --            --         51,312         --           --           51,312
Net income March 14, 2000
  through December 31, 2000 ..........        --           --            --         81,257         --           --           81,257
Other comprehensive income:
  Foreign currency translation
     adjustment ......................        --           --            --           --        (82,996)        --          (82,996)
Minimum pension liability adjustment,
  net of tax of $1,699 ...............        --           --            --           --         (2,388)        --           (2,388)
Unrealized gains on securities,
  net of tax of $1,164................        --           --            --           --          2,160         --            2,160
                                                                                                                        -----------
Total other comprehensive income .....                                                                                       49,345
Exercise of stock options and
  other equity transactions ..........          13         --            (138)        --           --            418            280
Teton Transaction ....................     (50,676)        --         304,132     (559,038)      37,324      749,770        532,188
-----------------------------------------------------------------------------------------------------------------------------------

BALANCE, DECEMBER 31, 2000 ...........       9,281         --       1,553,073       81,257      (57,929)        --        1,576,401

Net income ...........................        --           --            --        142,669         --           --          142,669
Other comprehensive income:
  Foreign currency translation
    adjustment .......................        --           --            --           --        (22,103)        --          (22,103)
Fair value adjustment on cash
  flow hedges, net of tax of $8,143 ..        --           --            --           --         18,490         --           18,490
Minimum pension liability adjustment,
  net of tax of $3,448 ...............        --           --            --           --         (4,847)        --           (4,847)
Unrealized losses on securities,
  net of tax of $1,315 ...............        --           --            --           --         (2,443)        --           (2,443)
                                                                                                                        -----------
Total other comprehensive income .....                                                                                      131,766
-----------------------------------------------------------------------------------------------------------------------------------

BALANCE, DECEMBER 31, 2001 ...........       9,281         --       1,553,073      223,926      (68,832)        --        1,708,167

Net income ...........................        --           --            --        380,043         --           --          380,043
Other comprehensive income:
  Foreign currency translation
    adjustment .......................        --           --            --           --        166,880         --          166,880
Fair value adjustment on cash
  flow hedges, net of tax of $10,106 .        --           --            --           --        (27,623)        --          (27,623)
Minimum pension liability adjustment,
  net of tax of $135,707 .............        --           --            --           --       (313,456)        --         (313,456)
Unrealized losses on securities,
  net of tax of $1,813 ...............        --           --            --           --         (3,204)        --           (3,204)
                                                                                                                        -----------
Total other comprehensive income .....                                                                                      202,640

Issuance of zero-coupon convertible
  preferred stock ....................        --           --         402,000         --           --           --          402,000
Retirement of stock options ..........        --           --             815      (19,960)        --           --          (19,145)
Other equity transactions ............        --           --             621         --           --           --              621
-----------------------------------------------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2002 ...........       9,281    $    --     $ 1,956,509    $ 584,009    $(246,235)   $    --      $ 2,294,283
===================================================================================================================================
</TABLE>

     The accompanying notes are an integral part of these financial statements

                                      -54-
<PAGE>
                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                             (Amounts in thousands)
<TABLE>
<CAPTION>
                                                                                                                 MEHC
                                                                                                            (PREDECESSOR)
                                                              YEAR ENDED DECEMBER 31,    MARCH 14, 2000    JANUARY 1, 2002
                                                             -------------------------      THROUGH           THROUGH
                                                                2002            2001    DECEMBER 31, 2000  MARCH 13, 2000
                                                             -----------     ---------  -----------------  --------------
<S>                                                          <C>             <C>           <C>             <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ..............................................    $   380,043     $ 142,669     $    81,257     $  51,312
Adjustments to reconcile net cash flows from
  operating activities:
  Income in excess of distributions on equity investments        (11,383)      (28,515)        (26,607)       (3,459)
  Gains on non-recurring items ..........................        (25,329)     (179,493)           --            --
  Depreciation and amortization .........................        525,902       442,284         303,354        83,097
  Amortization of excess of cost over fair value of net
     assets acquired ....................................           --          96,418          79,997        14,181
  Amortization of deferred financing and other costs ....         46,132        20,529          18,310         4,075
  Provision for deferred income taxes ...................        (16,228)      152,920         (15,460)        7,735
  Cumulative effect of change in accounting principle,
    net of tax ..........................................           --           4,604            --            --
  Changes in other items:
    Accounts receivable, net ............................       (244,829)      639,868        (333,277)      (11,769)
    Other current assets ................................         42,552       (20,041)         16,990        12,209
    Accounts payable and other accrued liabilities ......         36,083      (424,374)        124,030       (21,242)
    Accrued interest ....................................         68,924        (1,683)        (19,892)       35,701
    Accrued taxes .......................................        (39,302)       (4,616)          7,238        (4,270)
    Deferred income .....................................         (4,839)        6,428          10,467         3,513
                                                             -----------     ---------     -----------     ---------
    Net cash flows from operating activities ............        757,726       846,998         246,407       171,083
                                                             -----------     ---------     -----------     ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Acquisitions, net of cash acquired ....................     (1,416,937)      (81,934)     (2,048,266)         --
  Purchase of convertible preferred securities ..........       (275,000)         --              --            --
  Capital expenditures relating to operating projects ...       (542,615)     (398,165)       (301,948)      (44,355)
  Construction and other development costs ..............       (965,470)     (178,587)       (236,781)      (79,186)
  Proceeds from sale of assets ..........................        214,070       377,396            --            --
  Decrease in restricted cash and investments ...........         16,351        24,540         157,905        48,788
  Other .................................................         61,790        18,206          39,930        19,879
                                                             -----------     ---------     -----------     ---------
     Net cash flows from investing activities ...........     (2,907,811)     (238,544)     (2,389,160)      (54,874)
                                                             -----------     ---------     -----------     ---------

CASH FLOWS FROM FINANCING ACTIVITIES:
  Proceeds from subsidiary and project debt .............      1,485,349       200,000         262,176         6,043
  Proceeds from parent company debt .....................        700,000          --              --            --
  Repayments of subsidiary and project debt .............       (395,370)     (437,372)       (234,776)       (3,135)
  Net proceeds from (repayment of) corporate revolver ...       (153,500)       68,500          85,000          --
  Repayment of other obligations ........................        (94,297)         --            (4,225)         --
  Net repayment of subsidiary short-term debt ...........       (472,835)      (74,144)        (88,106)     (124,761)
  Proceeds from issuance of trust preferred securities ..      1,273,000          --           454,772          --
  Proceeds from issuance of common and preferred stock ..        402,000          --         1,428,024          --
  Redemption of preferred securities of subsidiaries ....       (127,908)      (24,910)        (20,409)         --
  Other .................................................        (61,205)        9,459          (3,607)       (6,648)
                                                             -----------     ---------     -----------     ---------
    Net cash flows from financing activities ............      2,555,234      (258,467)      1,878,849      (128,501)
                                                             -----------     ---------     -----------     ---------
  Effect of exchange rate changes .......................         52,536        (1,394)         (1,555)         (424)
                                                             -----------     ---------     -----------     ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ....        457,685       348,593        (265,459)      (12,716)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ........        386,745        38,152         303,611       316,327
                                                             -----------     ---------     -----------     ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ..............    $   844,430     $ 386,745     $    38,152     $ 303,611
                                                             ===========     =========     ===========     =========
SUPPLEMENTAL DISCLOSURE:
Interest paid, net of interest capitalized ..............    $   588,972     $ 389,953     $   351,532     $  35,057
                                                             ===========     =========     ===========     =========
Income taxes paid .......................................    $   101,225     $ 133,139     $    94,405     $    --
                                                             ===========     =========     ===========     =========
</TABLE>

   The accompanying notes are an integral part of these financial statements.
                                      -55-
<PAGE>
                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. ORGANIZATION AND OPERATIONS

MidAmerican  Energy  Holdings  Company and its  subsidiaries  (the  "Company" or
"MEHC") is a United  States-based  privately  owned global energy  company.  The
Company's  subsidiaries' principal businesses are regulated electric and natural
gas utilities,  regulated interstate natural gas transmission and electric power
generation.   Its  operations  are  organized  and  managed  on  seven  distinct
platforms:  MidAmerican Energy Company  ("MidAmerican  Energy"),  Kern River Gas
Transmission  Company ("Kern River"),  Northern  Natural Gas Company  ("Northern
Natural  Gas"),  CE  Electric UK Funding  ("CE  Electric  UK")  (which  includes
Northern  Electric plc  ("Northern  Electric")  and  Yorkshire  Power Group Ltd.
("Yorkshire")),  CalEnergy Generation - Domestic,  CalEnergy  Generation-Foreign
(the Upper Mahiao,  Malitbog and Mahanagdong  Projects  (collectively the "Leyte
Projects")  and  the  Casecnan  Project)  and  HomeServices  of  America,   Inc.
("HomeServices").  Through six of these platforms, the Company owns and operates
a combined  electric and natural gas utility  company in the United States,  two
natural  gas  pipeline   companies  in  the  United  States,   two   electricity
distribution  companies in the United  Kingdom,  and a diversified  portfolio of
domestic and international independent power projects. The Company also owns the
second largest residential real estate brokerage firm in the United States.

On March 14,  2000,  the Company and an investor  group  comprised  of Berkshire
Hathaway  Inc.,  Walter Scott,  Jr., a director of the Company,  David L. Sokol,
Chairman  and Chief  Executive  Officer  of the  Company,  and  Gregory E. Abel,
President  and Chief  Operating  Officer of the Company,  closed on a definitive
agreement  and plan of merger  whereby the  investor  group  acquired all of the
outstanding common stock of the Company (the "Teton  Transaction").  As a result
of the Teton Transaction,  Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel
own approximately 9.7%, 86%, 3% and 1% of the voting stock respectively.

The  Company  initially  incorporated  in 1971  under  the laws of the  State of
Delaware and was  reincorporated  in 1999 in Iowa,  at which time it changed its
name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.

In  these  notes  to  consolidated  financial  statements,  references  to "U.S.
dollars,"  "dollars,"  "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. References to MW means megawatts, MWh
means  megawatt  hours,  Bcf means billion cubic feet,  mmcf means million cubic
feet,  GWh means  gigawatts  per hour, kV means 1000 volts,  Tcf means  trillion
cubic feet, kWh means kilowatt  hours and MMBtus means million  British  thermal
units.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation
---------------------------

 The consolidated  financial  statements include the accounts of the Company and
its wholly-owned  subsidiaries.  Subsidiaries which are less than 100% owned but
greater than 50% owned are consolidated with a minority  interest.  Subsidiaries
that are 50% owned or less,  but where the  Company  has the ability to exercise
significant influence,  are accounted for under the equity method of accounting.
Investments  where the  Company's  ability to influence is limited are accounted
for  under the cost  method  of  accounting.  All  significant  inter-enterprise
transactions and accounts have been eliminated. The results of operations of the
Company  include the Company's  proportionate  share of results of operations of
entities  acquired  from  the date of each  acquisition  for  purchase  business
combinations.

For the Company's foreign  operations whose functional  currency is not the U.S.
dollar,  the assets and liabilities are translated into U.S.  dollars at current
exchange rates.  Resulting translation  adjustments are reflected as accumulated
other comprehensive income (loss) in stockholders' equity.  Revenue and expenses
are translated at average exchange rates for the period.  Transaction  gains and
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.

                                      -56-

<PAGE>

Reclassifications
-----------------

Certain amounts in the fiscal 2001 and 2000  consolidated  financial  statements
and supporting note disclosures have been  reclassified to conform to the fiscal
2002 presentation.  Such reclassification did not impact previously reported net
income or retained earnings.

Use of Estimates
----------------

The  preparation  of  consolidated   financial  statements  in  conformity  with
accounting  principles  generally  accepted  in the  United  States  of  America
requires  management to make estimates and assumptions  that affect the reported
amounts  of assets and  liabilities  and  disclosure  of  contingent  assets and
liabilities  at the  date  of the  consolidated  financial  statements  and  the
reported  amounts of revenue and expenses  during the reporting  period.  Actual
results could differ from those estimates.

Accounting for the Effects of Certain Types of Regulation
---------------------------------------------------------

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

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

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

Cash and Cash Equivalents
--------------------------

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

Restricted Cash and Investments
-------------------------------

The  current  restricted  cash  and  short-term   investments  balance  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  Company's  nuclear   decommissioning   trust  funds  and  other  marketable
securities  are  classified  as available for sale and are accounted for at fair
value.

                                      -57-
<PAGE>

Allowance for Doubtful Accounts
-------------------------------

The allowance for doubtful accounts is based on the Company's  assessment of the
collectibility of payments from its customers. This assessment requires judgment
regarding  the  outcome of pending  disputes,  arbitrations  and the  ability of
customers to pay the amounts owed to the  Company.  Any change in the  Company's
assessment of the collectibility of accounts  receivable that was not previously
provided is recorded in the current period.

Fair Value of Financial Instruments
-----------------------------------

The fair value of a financial  instrument is the amount at which the  instrument
could be exchanged in a current transaction between willing parties,  other than
in a forced sale or liquidation.  Although  management uses its best judgment in
estimating  the fair value of these  financial  instruments,  there are inherent
limitations in any estimation  technique.  Therefore,  the fair value  estimates
presented herein are not necessarily  indicative of the amounts that the Company
could realize in a current transaction.

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

Short-term debt - Due to the short-term  nature of the short-term debt, the fair
value approximates the carrying value.

Debt  instruments  - The fair value of all debt issues  listed on exchanges  has
been  estimated  based on the quoted  market  prices.  The  Company is unable to
estimate  a fair  value  for the  Philippine  term  loans as there are no quoted
market prices available.

Other  financial  instruments - All other  financial  instruments  of a material
nature are short-term and the fair value approximates the carrying amount.

Properties, Plants and Equipment, Net
-------------------------------------

Properties,  plants and equipment are recorded at historical  cost.  The cost of
major   additions  and   betterments  are   capitalized,   while   replacements,
maintenance,  and  repairs  that do not  improve  or  extend  the  lives  of the
respective assets are expensed.

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

Impairment of Long-Lived Assets
-------------------------------

The Company's  long-lived  assets consist  primarily of  properties,  plants and
equipment.  Depreciation  is computed  using the  straight-line  method based on
economic lives or regulatory mandated recovery periods. The Company believes the
useful lives assigned to the depreciable assets, which generally range from 3 to
87 years, are reasonable.

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

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

                                      -58-
<PAGE>

compared  to the  carrying  value  of the  assets.  An  impairment  analysis  of
generating  facilities requires estimates of possible future market prices, load
growth,  competition and many other factors over the lives of the facilities.  A
resulting impairment loss is highly dependent on these underlying assumptions.

Excess of Cost over Fair Value of Net Assets Acquired
-----------------------------------------------------

On January 1, 2002,  the  Company  adopted  SFAS No.  142,  "Goodwill  and Other
Intangible  Assets" ("SFAS 142"),  which establishes the accounting for acquired
goodwill  and  other   intangible   assets,   and  provides  that  goodwill  and
indefinite-lived intangible assets will not be amortized, but will be tested for
impairment on an annual  basis.  The Company's  related  amortization  consisted
primarily of goodwill amortization.  Following is a reconciliation of net income
available to common and preferred  stockholders  as originally  reported for the
years ended  December  31, 2002 and 2001 and for the periods from March 14, 2000
through December 31, 2000 and January 1, 2000 through March13, 2000, to adjusted
net  income  available  to common and  preferred  stockholders  (in  thousands):
<TABLE>
<CAPTION>


                                                                                                      MEHC (PREDECESSOR)
                                                        YEAR ENDED DECEMBER 31,    MARCH 14, 2000     JANUARY 1, 2002
                                                        -----------------------        THROUGH             THROUGH
                                                           2002        2001        DECEMBER 31, 2000    MARCH 13, 2000
                                                         --------    ---------     -----------------  -----------------
<S>                                                      <C>         <C>               <C>               <C>
Reported net income available to common
  and preferred stockholders ........................    $380,043    $ 142,669         $  81,257         $ 51,312
Amortization of excess of cost over fair value of net
  assets acquired ...................................        --         96,418            79,997           14,181
Tax effect of amortization ..........................        --         (2,018)           (1,413)            (372)
                                                         --------    ---------         ---------         --------
Adjusted net income available to common
and preferred stockholders ..........................    $380,043    $ 237,069         $ 159,841         $ 65,121
                                                         ========    =========         =========         ========
</TABLE>

The  Company  completed  its  initial  review  pursuant  to SFAS No. 142 for its
reporting  units during the second  quarter of 2002 and its annual review during
the fourth  quarter of 2002.  No  impairment  was indicated as a result of these
assessments.

Capitalization of Interest and Allowance for Funds Used During Construction
---------------------------------------------------------------------------

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

Deferred Financing Costs
------------------------

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

Contingent Liabilities
----------------------

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

                                      -59-

<PAGE>
Deferred Income Taxes
---------------------

The  Company  recognizes  deferred  tax  assets  and  liabilities  based  on the
difference  between  the  financial  statement  and  tax  basis  of  assets  and
liabilities  using  estimated  tax  rates in  effect  for the year in which  the
differences  are expected to reverse.  The Company does not intend to repatriate
earnings  of  foreign  subsidiaries  in the  foreseeable  future.  As a  result,
deferred  United States  income taxes are not provided for retained  earnings of
international  subsidiaries and corporate joint ventures unless the earnings are
intended to be remitted.

Revenue Recognition
-------------------


Revenue is recorded based upon services rendered and electricity,  gas and steam
delivered, distributed or supplied to the end of the period. The Company records
unbilled revenue representing the estimated amounts customers will be billed for
services  rendered between the meter reading dates in a particular month and the
end of that month.  The unbilled  revenue  estimate is reversed in the following
month.  To the extent  the  estimated  amount  differs  from the  actual  amount
subsequently billed, revenue will be affected.


Where there is an over recovery of United Kingdom distribution  business revenue
against  the  maximum  regulated  amount,  revenue  is  deferred  in  an  amount
equivalent to the over recovered  amount.  The deferred  amount is deducted from
revenue and included in other liabilities.  Where there is an under recovery, no
anticipation of any potential future recovery is made.

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

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

Financial Instruments
---------------------

The Company currently  utilizes swap agreements and forward purchase  agreements
to manage market risks and reduce its exposure  resulting  from  fluctuation  in
interest rates, foreign currency exchange rates and electric and gas prices. For
interest  rate swap  agreements,  the net cash  amounts  paid or received on the
agreements  are accrued and  recognized as an  adjustment  to interest  expense.
Gains and losses  related to gas forward  contracts are deferred and included in
the  measurement  of the related gas  purchases.  These  instruments  are either
exchange traded or with  counterparties of high credit quality;  therefore,  the
risk of nonperformance by the counterparties is considered to be negligible.

Accounting Principle Change
---------------------------

Effective  January 1, 2001,  the  Company  has  changed  its  accounting  policy
regarding  major   maintenance  and  repairs  for  non-regulated  gas  projects,
non-regulated  plant  overhaul  costs and  geothermal  well rework  costs to the
direct  expense  method  from the  former  policy of monthly  accruals  based on
long-term  scheduled  maintenance  plans for the gas  projects  and deferral and
amortization  of plant overhaul costs and geothermal  well rework costs over the
estimated  useful  lives.  The  cumulative  effect of the  change in  accounting
principle  was $4.6 million,  net of taxes of $0.7  million.  If the Company had
adopted the policy as of January 1, 2000, income before  extraordinary  item and
cumulative effect of change in accounting principle would have been $6.3 million
lower in 2000 on a pro forma basis.

NEW ACCOUNTING PRONOUNCEMENTS

In August 2001, the FASB issued SFAS No. 143,  "Accounting for Asset  Retirement
Obligations"  ("SFAS 143").  This statement  provides  accounting and disclosure
requirements for retirement obligations associated with long-lived assets and is
effective  January 1, 2003.  This  statement  requires that the present value of
retirement  costs for which the  Company has a legal  obligation  be recorded as
liabilities  with an equivalent  amount added to the asset cost and  depreciated
over an appropriate period. The liability is then accreted over time by applying
an interest  method of allocation  to the  liability.  Cumulative  accretion and
accumulated  depreciation  will be recognized  for the time period from

                                      -60-
<PAGE>

the date the liability  would have been  recognized  had the  provisions of this
statement  been in  effect,  to the  date of  adoption  of this  statement.  The
cumulative effect of initially applying this statement is recognized as a change
in accounting principle.  The Company and its unconsolidated  subsidiary used an
expected cash flow approach to measure the obligations and adopted the statement
as of January 1, 2003.

The  Company's  initial  review  of  its  regulated  entities  identified  legal
retirement  obligations for nuclear  decommissioning,  wet and dry ash landfills
and offshore  and minor  lateral  pipeline  facilities.  The Company  expects to
record approximately $290.0 million of asset retirement obligation  liabilities,
approximately  $265.0 million of which pertains to obligations  associated  with
the  decommissioning  of the Quad Cities nuclear  station.  The adoption of this
statement is not  expected to have a material  impact on the  operations  of the
regulated   entities,   as  the  effects  are  expected  to  be  offset  by  the
establishment  of regulatory  assets,  totaling  approximately  $115.0  million,
pursuant to SFAS 71.

In addition,  one of the Company's  unconsolidated  subsidiaries  has identified
legal  retirement  obligations  for landfill and plant  abandonment  costs.  The
Company's share of this adoption is expected to total $1.1 million, net of tax.

In August 2001, the FASB issued SFAS No. 144,  "Accounting for the Impairment or
Disposal of Long-Lived  Assets" ("SFAS 144").  SFAS 144 provides new guidance on
the recognition of impairment losses on long-lived assets to be held and used or
to be  disposed  of and also  broadens  the  definition  of what  constitutes  a
discontinued operation and how the results of a discontinued operation are to be
measured and presented. SFAS 144 supercedes SFAS No. 121 and APB Opinion No. 30,
while retaining many of the  requirements  of these two  statements.  Under SFAS
144,  assets held for sale that are a component of an entity will be included in
discontinued  operations if the  operations  and cash flows will be or have been
eliminated  from the  ongoing  operations  of the entity and the entity will not
have any  significant  continuing  involvement in the operations  prospectively.
SFAS 144 did not  materially  change the methods  used by the Company to measure
impairment   losses  on  long-lived   assets  but  may  result  in  more  future
dispositions  being reported as discontinued  operations  than would  previously
have been permitted. The Company adopted SFAS 144 on January 1, 2002.

In April 2002, the FASB issued SFAS No. 145,  "Rescission of FASB Statements No.
4, 44, and 64,  Amendment of FASB  Statement No. 13, and Technical  Corrections"
("SFAS  145").  SFAS  145  eliminates  extraordinary  accounting  treatment  for
reporting  gains or losses on debt  extinguishment,  and amends  other  existing
authoritative  pronouncements  to make various  technical  corrections,  clarify
meanings,  or  describe  their  applicability  under  changed  conditions.   The
provisions  of SFAS 145 related to the  rescission  of FASB  Statement No. 4 are
applicable in fiscal years beginning after May 15, 2002, the provisions  related
to FASB Statement No. 13 are effective for transactions  occurring after May 15,
2002, and all other provisions are effective for financial  statements issued on
or  after  May  15,  2002;  however,  early  application  is  encouraged.   Debt
extinguishments  reported as  extraordinary  items prior to  scheduled  or early
adoption of SFAS 145 would be reclassified in most cases following adoption. The
Company  does not expect the  adoption of SFAS 145 to have a material  effect on
its financial position, results of operations, or cash flows.

In June 2002,  the FASB issued SFAS No. 146,  "Accounting  for Costs  Associated
with Exit or Disposal  Activities"  ("SFAS 146").  SFAS 146 nullifies EITF Issue
No. 94-3,  "Liability  Recognition for Certain Employee Termination Benefits and
Other  Costs  to  Exit  an  Activity  (including  Certain  Costs  Incurred  in a
Restructuring)"  ("EITF 94-3").  The principal  difference  between SFAS 146 and
EITF 94-3 relates to the  requirements  for recognition of a liability for costs
associated with an exit or disposal activity. SFAS 146 requires that a liability
be recognized for a cost associated with an exit or disposal activity when it is
incurred. A liability is incurred when a transaction or event occurs that leaves
an entity little or no discretion to avoid the future  transfer or use of assets
to settle  the  liability.  Under EITF 94-3,  a  liability  for an exit cost was
recognized  at the date of an entity's  commitment to an exit plan. In addition,
SFAS 146 also requires that a liability  for a cost  associated  with an exit or
disposal activity be recognized at its fair value when it is incurred.  SFAS 146
is effective for exit or disposal  activities  that are initiated after December
31,  2002  with  early  application  encouraged.  The  Company  will  apply  the
provisions  of SFAS  146 to all  exit or  disposal  activities  initiated  after
December 31, 2002.

In  November  2002,  the FASB issued FASB  Interpretation  No. 45,  "Guarantor's
Accounting  and  Disclosure  Requirements  for  Guarantees,  Including  Indirect
Guarantees  of  Indebtedness  of Others"  ("FIN  45").  FIN 45  requires  that a
liability be recorded in the guarantor's  balance sheet upon issuance of certain
guarantees.  In addition,  FIN 45 requires disclosures about the guarantees that
an entity has issued.  The provision for initial  recognition and measurement of
the  liability  will be applied on a prospective  basis to guarantees  issued or
modified  after  December  31, 2002.  The  disclosure  provisions  of FIN 45 are
effective for financial  statements  of interim or annual  periods  ending after
December 15, 2002.  The Company does not expect the adoption of FIN 45 to have a
material effect on its financial position, results of operations, or cash flows.

                                      -61-
<PAGE>

3. ACQUISITIONS

Kern River
----------

On March 27,  2002,  the  Company  acquired  Kern River,  a 926-mile  interstate
pipeline  transporting  Rocky  Mountain and  Canadian  natural gas to markets in
California, Nevada and Utah.

The Company  paid $419.7  million,  net of cash  acquired of $7.7  million and a
working  capital  adjustment,  for  Kern  River's  gas  pipeline  business.  The
acquisition  has been  accounted  for as a purchase  business  combination.  The
Company is in the process of completing  the allocation of the purchase price to
the assets and  liabilities  acquired.  The results of operations for Kern River
are included in the Company's results beginning March 27, 2002.

The  recognition  of  excess  of cost over  fair  value of net  assets  acquired
resulted  from various  attributes  of Kern River's  operations  and business in
general. These attributes include, but are not limited to:

     o    Opportunities for expansion;

     o    High credit  quality  shippers  contracting  with Kern  River;  o Kern
          River's strong  competitive  position;  o Exceptional  operating track
          record and state-of-the-art technology; o Strong demand for gas in the
          Western markets; and

     o    An ample supply of low-cost gas.

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

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

       Cash .................................................     $    7.7
       Properties, plants and equipment .....................        797.2
       Excess of cost over fair value of  net assets acquired         32.5
       Other assets .........................................        173.2
                                                                  --------
         Total assets acquired ..............................      1,010.6
                                                                  --------
       Current liabilities ..................................       (105.4)
       Long-term debt .......................................       (482.0)
       Other liabilities ....................................         (0.9)
                                                                  --------
         Total liabilities assumed ..........................       (588.3)
                                                                  --------
       Net assets acquired ..................................     $  422.3
                                                                  ========

Northern Natural Gas Company
----------------------------

On August 16, 2002, the Company  acquired  Northern Natural Gas from Dynegy Inc.
("Dynegy").  Northern Natural Gas is a 16,600-mile interstate pipeline extending
from southwest Texas to the upper Midwest region of the United States.

The Company paid $882.7  million for Northern  Natural Gas, net of cash acquired
of $1.4 million and net of a working  capital  adjustment.  The  acquisition has
been  accounted for as a purchase  business  combination.  The Company is in the
process of completing  the  allocation  of the purchase  price to the assets and
liabilities  acquired.  The results of operations  for Northern  Natural Gas are
included in the Company's results beginning August 16, 2002.

                                      -62-

<PAGE>

The  recognition  of  excess  of cost over  fair  value of net  assets  acquired
resulted  from  various  attributes  of Northern  Natural  Gas'  operations  and
business in general. These attributes include, but are not limited to:

     o    High credit quality shippers  contracting with Northern Natural Gas; o
          Northern Natural Gas' strong competitive position;
     o    Strategic location in the high demand Upper Midwest markets;
     o    Flexible access to an ample supply of low-cost gas;
     o    Exceptional operating track record; and
     o    Opportunities for expansion.

In connection with the  acquisition of Northern  Natural Gas, the Company issued
$950.0  million  of  11%  Company-obligated   mandatorily  redeemable  preferred
securities of subsidiary  trust due August 31, 2011,  with  scheduled  principal
payments beginning in 2003, to Berkshire Hathaway.

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

       Cash .................................................   $    1.4
       Properties, plants and equipment .....................    1,346.7
       Excess of cost over fair value of  net assets acquired      414.7
       Other assets .........................................      309.9
                                                                --------
         Total assets acquired ..............................    2,072.7
                                                                --------
       Current portion of long-term debt ....................     (450.0)
       Other current liabilities ............................     (216.1)
       Long-term debt .......................................     (499.8)
       Other liabilities ....................................      (27.7)
                                                                --------
         Total liabilities assumed ..........................   (1,193.6)
                                                                --------
       Net assets acquired ..................................   $  879.1
                                                                ========

The following pro forma  financial  information  of the Company  represents  the
unaudited  pro forma  results of  operations  as if the Kern River and  Northern
Natural  Gas  acquisitions,  and the  related  financings,  had  occurred at the
beginning  of each  period.  These pro forma  results  have  been  prepared  for
comparative  purposes only and do not profess to be indicative of the results of
operations which would have been achieved had these  transactions been completed
at the beginning of each year,  nor are the results  indicative of the Company's
future results of operations (in millions).

                                                    YEAR ENDED
                                                   DECEMBER 31,
                                                -------------------
                                                  2002       2001
                                                --------   --------

            Revenue .........................   $5,299.4   $5,688.5
            Income before cumulative effect
            of change in accounting principle      285.5       36.9
            Net income available to common
             and preferred shareholders .....      285.5       32.3

HomeServices' 2002 Acquisitions
-------------------------------

In 2002,  HomeServices  separately  acquired three real estate  companies for an
aggregate purchase price of approximately  $106.1 million, net of cash acquired,
plus working capital and certain other adjustments.  For the year ended December
31, 2001,  these real estate  companies  had combined  revenue of  approximately
$356.0  million  on 42,000  closed  sides  representing  $13.7  billion of sales
volume.  Additionally,  HomeServices  is obligated  to pay a maximum  earnout of
$18.5 million based on 2002 financial performance measures. These purchases were
financed using HomeServices'  internally generated cash flows,  revolving credit
facility  and  $40.0  million  from  the  Company,   which  was  contributed  to
HomeServices as equity.

                                      -63-
<PAGE>


The acquisitions have been accounted for as a purchase business combination. The
purchase price has been allocated to assets  acquired and  liabilities  assumed.
The Company recorded goodwill of approximately $108.9 million.

Yorkshire Swap
--------------

On September 21, 2001, CE Electric UK Ltd, an indirect  wholly owned  subsidiary
of the Company,  and Innogy  Holdings,  plc ("Innogy")  executed an agreement to
exchange Northern' Electrics  electricity and gas supply and metering assets for
Innogy's  94.75%  interest in  Yorkshire's  electricity  distribution  business.
Northern  Electric's supply business was valued at approximately  $391.0 million
((pound)268.0 million), including working capital of approximately $14.0 million
((pound)10.0 million). 94.75% of Yorkshire's distribution business was valued at
approximately $405.0 million ((pound)278.0  million),  including working capital
of  approximately  $58.0  million  ((pound)40.0  million).  The net cash paid by
Northern Electric for the exchange was approximately $14.0 million  ((pound)10.0
million).

The  disposition  of  Northern  Electric's  supply  business  created  a pre-tax
non-recurring  gain of $196.7  million and an after-tax  gain of $10.8  million.
Included in the carrying  value of the  Northern  Electric  supply  business was
$504.4  million of goodwill  allocated  based on the relative fair values of the
Northern Electric supply business.

The Company  paid $57.4  million,  net of cash  acquired  of $353.8  million and
transaction costs, for 94.75% of the Yorkshire electricity distribution business
and related  indebtedness.  The acquisition has been accounted for as a purchase
business  combination.  The results of operations  for Yorkshire are included in
the Company's results beginning September 21, 2001.

Teton Transaction
-----------------

On October 24, 1999,  the Company and an investor  group  comprised of Berkshire
Hathaway, Walter Scott, Jr., and David L. Sokol, executed a definitive agreement
and  plan  of  merger  whereby  the  investor  group  would  acquire  all of the
outstanding  common  stock  of  the  Company  for  $35.05  per  share  in  cash,
representing  a total purchase price of  approximately  $2.2 billion,  including
transaction  costs. The Teton Transaction closed on March 14, 2000 and Berkshire
Hathaway  invested  approximately  $1.24 billion in common stock and convertible
preferred  stock and  approximately  $455 million in 11%  nontransferable  trust
preferred  securities  due March 14, 2010.  Mr. Scott,  Mr. Sokol and Gregory E.
Abel  contributed  cash and current  securities of the Company having a value of
approximately  $310 million.  The remaining  purchase  price was funded with the
Company's cash.  Berkshire Hathaway owns approximately 9.7% of the voting stock,
Mr.  Scott  owns   approximately  86%  of  the  voting  stock,  Mr.  Sokol  owns
approximately  3% of the voting stock and Mr. Abel owns  approximately 1% of the
voting stock.

The  merger  has been  accounted  for as a purchase  business  combination.  The
purchase price has been allocated to assets  acquired and  liabilities  assumed.
The Company recorded goodwill of approximately $1.2 billion.

4. DISPOSITIONS AND OTHER NON-RECURRING ITEMS

CE Gas Asset Sale
-----------------

In May 2002,  CE Gas,  an  indirect  wholly  owned  subsidiary  of the  Company,
executed the sale of several of its U.K. natural gas assets to Gaz de France for
(pound)137.0 million  (approximately  $200.0 million).  CE Gas sold four natural
gas-producing  fields  located  in the  southern  basin of the U.K.  North  Sea,
including  Anglia,  Johnston,  Schooner and  Windermere.  The  transaction  also
included the sale of rights in four gas fields (in development/construction) and
three  exploration  blocks  owned by CE Gas.  The Company  recorded  pre-tax and
after-tax  income  of $54.3  million  and  $41.3  million,  respectively,  which
includes a write off of non-deductible goodwill of $49.6 million.

Telephone Flat Sale
-------------------

On October 16, 2001, the Company closed on a transaction  that  transferred  all
properties  and rights of the Telephone Flat Project,  a geothermal  development
project in northern  California to Calpine Corp. The Company  recorded a pre-tax
gain of $20.7 million and an after-tax  gain of $12.2 million on the sale of the
Telephone Flat Project.

                                      -64-
<PAGE>

Western States Sale
-------------------

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

Tesside Power Limited ("TPL")
-----------------------------

In December 2001, the Company recorded a non-recurring  charge of $20.7 million,
net of tax,  representing  an asset valuation  impairment  charge under SFAS No.
121,  "Accounting for the Impairment of Long-Lived Assets" ("SFAS 121") relating
to the  Company's  15.4%  interest  in TPL.  TPL  owns and  operates  a 1,875 MW
combined  cycle  gas-fired  power  plant.  Enron  Corp.  ("Enron"),  through its
subsidiaries,  owned a 42.5% interest,  operated the plant, and purchased 668 MW
of  capacity.  Enron's  subsidiary,  which  owns  and  operates  TPL,  is now in
administration  and  administrators  have been appointed to run its business and
are attempting to find a buyer.

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


5. PROPERTIES, PLANTS AND EQUIPMENT, NET

Properties,  plants and equipment, net comprise the following at December 31 (in
thousands):
<TABLE>
<CAPTION>

                                                   ESTIMATED          DECEMBER 31,
                                                  USEFUL LIVES  -------------------------
                                                     (Years)        2002          2001
                                                  ------------  -----------   -----------
<S>                                                   <C>       <C>           <C>
Properties, plants and equipment, net:
  Utility generation and distribution system ....     10-50     $ 8,165,140   $ 7,574,339
  Interstate pipelines' assets ..................      3-87       2,171,436          --
  Independent power plants ......................     10-30       1,410,170     1,402,102
  Mineral and gas reserves and exploration assets      5-30         495,423       387,697
  Utility non-operational assets ................      3-30         370,811       354,366
  Other assets ..................................      3-10         130,755       153,211
                                                                -----------   -----------
    Total operating assets ......................                12,743,735     9,871,715
                                                                -----------   -----------
  Accumulated depreciation and amortization .....                (4,104,133)   (3,650,875)
                                                                -----------   -----------
  Net operating assets ..........................                 8,639,602     6,220,840
  Construction in progress ......................                 1,170,485       316,531
                                                                -----------   -----------
    Properties, plants and equipment, net .......               $ 9,810,087   $ 6,537,371
                                                                ===========   ===========
</TABLE>

Construction in Progress
------------------------

MidAmerican  Energy is  constructing a 500-MW (based on expected  accreditation)
natural gas-fired,  combined cycle plant with an estimated cost of $415 million.
MidAmerican  Energy will own 100% of the plant and operate it. The plant will be
operated  in simple  cycle mode  during  2003 and 2004,  resulting  in 310 MW of
accredited  capacity.  The  combined  cycle  operation  will  commence  in 2005.
MidAmerican  Energy has received a certificate  from the Iowa  Utilities  Board,
"(IUB"),  allowing it to  construct  the plant.  In May 2002,  the IUB issued an
order that specified the Iowa ratemaking principles that will apply to the plant
over its life. As a result of that order,  MidAmerican Energy is proceeding with
the construction of the plant.

The 2003  Expansion  Project is a new parallel  717-mile loop pipeline that will
begin in Lincoln County, Wyoming and terminate in Kern County,  California.  The
2003 Expansion  Project began  construction on August 6, 2002 and is expected to
be completed  and  operational  by May 1, 2003 at a total cost of  approximately
$1.2 billion.  The pipeline will include 36- and 42-inch  diameter pipe, most of
which will be laid in the existing Kern River  rights-of-way at a 25-foot offset
from the

                                      -65-
<PAGE>
existing  pipeline,  and new above ground  facilities.  Three  segments
along the rights-of-way, approximately 205 miles in Utah, Nevada and California,
will not require  additional  pipeline  but will  instead be areas where the gas
will be compressed and transported  through the existing pipeline.  The existing
pipeline  rights-of-way,  compressor facilities and receipt/delivery  facilities
will all be utilized by the 2003 Expansion Project, streamlining the permitting,
acquisition of  rights-of-way  and ultimately the construction and operations of
the 2003 Expansion Project.

The 2003 Expansion  Project  includes the  construction  of three new compressor
stations and the installation of additional  compression and other modifications
at six existing  facilities.  When completed,  the Kern River system will have a
summer day design  capacity  of  approximately  1.73 Bcf per day, an increase of
approximately 886 mmcf per day.

6. INVESTMENT IN CE GENERATION

Since the sale of 50% of its interests in CE  Generation  on March 3, 1999,  the
Company has  accounted for CE  Generation  as an equity  investment.  The equity
investment  in CE  Generation  at December  31, 2002 and 2001 was  approximately
$244.9  million and $233.6  million,  respectively.  The following is summarized
financial  information  for CE Generation as of and for the years ended December
31 (in thousands):

                                                 2002        2001        2000
                                              ----------  ----------  --------

Revenue ....................................  $  510,082  $  565,838  $510,796
Income before cumulative effect of change in
  accounting principle .....................      58,314      74,194    73,535
Net income .................................      58,314      58,808    73,535

Current assets .............................     202,490     211,635
Total assets ...............................   1,865,036   1,932,119
Current liabilities ........................     150,165     155,808
Long-term debt, including current portion ..   1,011,220   1,096,256

7. OTHER INVESTMENTS

Williams' Company Preferred Stock
---------------------------------

On March 27, 2002, a newly formed  subsidiary of the Company,  MEHC  Investments
Inc.,  invested  $275.0  million in Williams  in  exchange  for shares of 9 7/8%
cumulative  convertible preferred stock of Williams.  Dividends on the Williams'
preferred stock are scheduled to be received quarterly,  which commenced July 1,
2002. This investment is accounted for under the cost method.  Since the date of
this investment,  there have been public  announcements that Williams' financial
condition  has  deteriorated  as a  result  of,  among  other  factors,  reduced
liquidity.  The Company has not recorded an impairment on this  investment as of
December 31, 2002, and is monitoring the situation.

                                      -66-

<PAGE>

Investments in Debt and Equity Securities
-----------------------------------------

Substantially  all of the Company's  investments  in debt and equity  securities
relate to its Quad Cities Station  decommissioning  trust.  The amortized  cost,
gross unrealized gain and losses and estimated fair value of investments in debt
and equity securities comprise the following at December 31 (in thousands):

                                                        2002
                                    --------------------------------------------
                                    AMORTIZED  UNREALIZED  UNREALIZED     FAIR
                                       COST      GAINS      LOSSES       VALUE
                                    ---------  ----------  ----------   --------
Available-for-sale:
  Equity securities .............    $ 56,265    $16,373    $(1,313)    $ 71,325
  Municipal bonds ...............      30,915        918       (263)      31,570
  U. S. Government securities ...      18,511        183       (119)      18,575
  Corporate securities ..........      25,258      1,152        (80)      26,330
  Cash equivalents ..............      12,718       --         --         12,718
                                     --------    -------    -------     --------
    Total available-for-sale ....    $143,667    $18,626    $(1,775)    $160,518
                                     ========    =======    =======     ========

HELD-TO-MATURITY:
  Debt securities ...............    $  2,070    $  --      $  --       $  2,070
  U.S. Treasury Strips ..........       1,485        208       --          1,693
  Agency obligations ............         216        111       --            327
                                     --------    -------    -------     --------
    Total held-to-maturity ......    $  3,771    $   319    $  --       $  4,090
                                     ========    =======    =======     ========

                                                        2001
                                   ---------------------------------------------
                                    AMORTIZED  UNREALIZED  UNREALIZED    FAIR
                                      COST        GAINS      LOSSES      VALUE
                                   ----------  ----------  ----------  ---------
Available-for-sale:
  Equity securities .............    $ 53,663    $24,444    $(3,144)    $ 74,963
  Municipal bonds ...............      27,842      1,315        (92)      29,065
  U. S. Government securities ...      26,725      1,910        (19)      28,616
  Corporate securities ..........      18,682        812        (23)      19,471
  Cash equivalents ..............       7,120       --         --          7,120
                                     --------    -------    -------     --------
    Total available-for-sale ....    $134,032    $28,481    $(3,278)    $159,235
                                     ========    =======    =======     ========

HELD-TO-MATURITY:
  Debt securities ...............    $  2,074    $  --      $  --       $  2,074
  U.S. Treasury Strips ..........       1,090         85       --          1,175
  Agency obligations ............         611       --          (22)         589
                                     --------    -------    -------     --------
    Total held-to-maturity ......    $  3,775    $    85    $   (22)    $  3,838
                                     ========    =======    =======     ========

At December 31, 2002, the debt  securities held by the Company had the following
maturities (in thousands):

                                AVAILABLE FOR SALE    HELD TO MATURITY
                                -------------------  ------------------
                                AMORTIZED    FAIR    AMORTIZED   FAIR
                                   COST      VALUE     COST     VALUE
                                ---------   -------  ---------  -------

         Within 1 year ......    $ 7,224    $ 7,384    $2,070    $2,070
         1 through 5 years ..     25,143     25,994       479       664
         5 through 10 years .     14,190     14,574     1,222     1,356
         Over 10 years ......     27,621     28,020      --        --

                                      -67-

<PAGE>


The  proceeds  and  gross  realized  gains  and  losses  on the  disposition  of
available-for-sale  and held-to-maturity  investments are shown in the following
table (in  thousands).  Realized  gains and losses are  determined  by  specific
identification.

                                                                    MEHC
                                                                (PREDECESSOR)
                             YEAR ENDED        MARCH 14, 2000  JANUARY 1, 2000
                             DECEMBER 31,         THROUGH         THROUGH
                           2002      2001   DECEMBER 31, 2000  MARCH 13, 2000
                         --------  -------  -----------------  ---------------

Proceeds from sales      $151,394  $68,333        $93,531         $ 22,588
Gross realized gains        7,099    2,676          6,464            1,560
Gross realized losses      (7,792)  (7,314)       (10,585)          (2,556)


8.  SHORT-TERM DEBT

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

                                                    2002       2001
                                                    -------   --------
         Short-term debt:
         Corporate revolving credit facility ....   $  --     $153,500
         MidAmerican Energy short-term debt .....    55,000     91,780
         HomeServices revolving credit facilities    24,750      9,000
         Other ..................................        32      1,732
                                                    -------   --------
         Total short-term debt ..................   $79,782   $256,012
                                                    =======   ========

Corporate Revolving Credit Facilities
-------------------------------------

The Company has a $400.0 million revolving credit facility which expires in June
2003.  The  facility  is  unsecured  and  available  to  fund  working   capital
requirements and other corporate  requirements.  The facility carries a variable
interest  rate based on LIBOR and  ranged  from  2.625% to  2.8625% in 2002.  No
borrowings were outstanding at December 31, 2002. The Company plans to renew the
facility in June 2003.

MidAmerican Energy Short-Term Debt
----------------------------------

As of  December  31,  2002,  MidAmerican  Energy  had in place a $370.4  million
revolving  credit  facility that supports its $250.0  million  commercial  paper
program  and  its  variable  rate  pollution  control  revenue  obligations.  In
addition,  MidAmerican  Energy has a $5.0 million line of credit. As of December
31, 2002,  commercial paper and bank notes totaled $55.0 million for MidAmerican
Energy. MHC Inc., an indirect wholly owned subsidiary of the Company, has a $4.0
million line of credit under which no borrowings  were  outstanding  at December
31, 2002. The commercial paper, bank notes and outstanding line of credit have a
weighted average interest rate of 1.29% at December 31, 2002.

HomeServices Revolving Credit Facilities
----------------------------------------

Upon the  expiration  of its  $65.0  million  senior  secured  revolving  credit
facility in November 2002, HomeServices entered into a new $125.0 million senior
secured  revolving  credit  agreement.  The new revolving credit agreement has a
term of three  years and is secured by a pledge of the  capital  stock of all of
the existing and future subsidiaries of HomeServices.  Amounts outstanding under
this revolving credit facility bear interest, at HomeServices' option, at either
the prime  lending  rate or LIBOR plus a fixed  spread of 1.25% to 2.25%,  which
varies based on  HomeServices'  cash flow leverage  ratio (1.25% at December 31,
2002). As of December 31, 2002, the  outstanding  balance of $24.8 million had a
weighted average interest rate of 2.6661%.

                                      -68-

<PAGE>

9.  PARENT COMPANY DEBT

Parent company debt is unsecured senior obligations of the Company and comprises
the following at December 31 (in thousands):

                                                     2002           2001
                                                 -----------    -----------
   Parent company debt:
     6.96% Senior Notes, due 2003 ............   $   215,000    $   215,000
     7.23% Senior Notes, due 2005 ............       260,000        260,000
     4.625% Senior Notes, due 2007 ...........       200,000           --
     7.63% Senior Notes, due 2007 ............       350,000        350,000
     7.52% Senior Notes, due 2008 ............       450,000        450,000
     7.52% Senior Notes, due 2008 (Series B) .       101,481        101,680
     5.875% Senior Notes, due 2012 ...........       500,000           --
     8.48% Senior Notes, due 2028 ............       475,000        475,000
     Fair value adjustments and other ........       (12,025)       (17,182)
                                                 -----------    -----------
       Total parent company debt .............     2,539,456      1,834,498
         Less current portion ................      (215,000)          --
                                                 -----------    -----------
       Total long-term parent company debt ...   $ 2,324,456    $ 1,834,498
                                                 ===========    ===========

Interest  on the 7.63%  Senior  Notes is  payable  semiannually  on April 15 and
October 15 of each year.  Interest  on the  4.625%  Senior  Notes and the 5.875%
Senior  Notes is  payable  semiannually  on January 31 and July 31 of each year.
Interest on the remaining  parent company debt is payable  semiannually on March
15 and September 15 of each year.

10.  SUBSIDIARY AND PROJECT LOANS

Each of the Company's  direct and 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.

                                      -69-
<PAGE>


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

                                                        2002           2001
                                                     -----------    -----------
Subsidiary and project loans:
  MidAmerican Funding Senior Notes and Bonds .....   $   700,000    $   700,000
  MidAmerican Energy Mortgage Bonds ..............       340,570        340,570
  MidAmerican Energy Pollution Control Bonds .....       155,745        157,185
  MidAmerican Energy Notes .......................       560,000        322,240
  MidAmerican Capital Notes ......................          --           23,333
  Northern Electric Eurobonds ....................       322,811        291,643
  CE Electric UK Senior Notes and Sterling Bonds .       677,642        646,500
  Yorkshire ......................................     1,573,136      1,491,597
  CE Gas Loan ....................................          --           70,180
  Kern River Senior Notes ........................       488,000           --
  Kern River Construction Financing Facility .....       789,916           --
  Northern Natural Gas Senior Notes ..............       799,406           --
  Cordova Funding Senior Secured Bonds ...........       223,763        225,000
  Salton Sea Funding Corporation Series F Bonds ..       137,789        139,896
  Casecnan Notes and Bonds .......................       287,925        320,138
  Philippine Term Loans ..........................       244,961        313,221
  HomeServices Senior Notes and Other ............        39,031         36,780
  Other, including fair value adjustments ........        (8,395)        (6,292)
                                                     -----------    -----------
    Total subsidiary and project loans ...........     7,332,300      5,071,991
      Less current portion .......................      (255,213)      (317,180)
                                                     -----------    -----------
    Total long-term subsidiary and project loans .   $ 7,077,087    $ 4,754,811
                                                     ===========    ===========

MidAmerican Funding Senior Notes and Bonds
------------------------------------------

On March  11,  1999,  MidAmerican  Funding,  a wholly  owned  subsidiary  of the
Company, issued $200.0 million of 5.85% Senior Secured Notes due in 2001, $175.0
million of 6.339% Senior Secured Notes due in 2009, and $325.0 million of 6.927%
Senior  Secured  Bonds due in 2029.  The proceeds from the offering were used to
complete the MidAmerican acquisition in 1999.

On March 1, 2001  MidAmerican  Funding  retired  $200.0  million of 5.85% Senior
Secured  Notes due 2001.  On March 19,  2001  MidAmerican  Funding  issued  $200
million of 6.75% Senior Secured Notes due March 1, 2011.

MidAmerican Funding uses distributions that it receives from its subsidiaries to
make  payments  on the Senior  Notes and  Bonds.  These  subsidiaries  must make
payments on their own  indebtedness  before making  distributions to MidAmerican
Funding.  The distributions are also subject to utility regulatory  restrictions
agreed to by MidAmerican Energy in March 1999 whereby it committed to the IUB to
use  commercially  reasonable  efforts to maintain an investment grade rating on
its  long-term  debt and to maintain its common  equity level above 42% of total
capitalization  unless  circumstances  beyond its  control  result in the common
equity  level  decreasing  to  below  39% of total  capitalization.  MidAmerican
Funding  must  seek the  approval  of the IUB of a  reasonable  utility  capital
structure if MidAmerican  Energy's  common equity level  decreases  below 42% of
total  capitalization,  unless the decrease is beyond the control of MidAmerican
Funding. MidAmerican Funding is also required to seek the approval of the IUB if
MidAmerican  Energy's  equity level decreases to below 39%, even if the decrease
is due to circumstances beyond the control of MidAmerican Funding.

                                      -70-
<PAGE>

MidAmerican Energy Mortgage Bonds, Pollution Control Bonds and Notes
--------------------------------------------------------------------

The components of MidAmerican  Energy's Mortgage Bonds,  Pollution Control Bonds
and Notes comprise the following at December 31 (in thousands):

                                                           2002       2001
                                                         --------   --------
    Mortgage bonds:
    7.125% Series, due 2003 ..........................   $100,000   $100,000
    7.70% Series, due 2004 ...........................     55,630     55,630
    7% Series, due 2005 ..............................     90,500     90,500
    7.375% Series, due 2008 ..........................     75,000     75,000
    7.45% Series, due 2023 ...........................      6,940      6,940
    6.95% Series, due 2025 ...........................     12,500     12,500
                                                         --------   --------
    Total mortgage bonds .............................   $340,570   $340,570
                                                         ========   ========

    Pollution control revenue obligations:
    5.75% Series, due periodically through 2003 ......   $  4,320   $  5,760
    5.95% Series, due 2023 ...........................     29,030     29,030
    6.7% Series, due 2003 ............................      1,000      1,000
    6.1% Series, due 2007 ............................      1,000      1,000
    Variable rate series:
    Due 2016 and 2017, 1.64% and 1.77% respectively ..     37,600     37,600
    Due 2023 (secured by general mortgage bond, 1.64%
    and 1.77%, respectively ..........................     28,295     28,295
    Due 2023, 1.64% and 1.77%, respectively ..........      6,850      6,850
    Due 2024, 1.64% and 1.77%, respectively ..........     34,900     34,900
    Due 2025, 1.64% and 1.77%, respectively ..........     12,750     12,750
                                                         --------   --------
    Total pollution control revenue obligations ......   $155,745   $157,185
                                                         ========   ========

    Notes:
    8.75% Series, due 2002 ...........................   $   --     $    240
    7.375% Series, due 2002 ..........................       --      162,000
    6.75% Series, due 2031 ...........................    400,000       --
    6.375% Series, due 2006 ..........................    160,000    160,000
                                                         --------   --------
    Total notes ......................................   $560,000   $322,240
                                                         ========   ========

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

                                      -71-
<PAGE>

CE Electric UK, Northern Electric and Yorkshire Electric Eurobonds, Senior Notes
--------------------------------------------------------------------------------
and Sterling Bonds
------------------

                                                         2002         2001
                                                      ----------   ----------
     Eurobonds:
     8.625% Bearer bonds, due 2005 ................   $  161,469   $  145,879
     8.875% Bearer bonds, due 2020 ................      161,342      145,764
                                                      ----------   ----------
     Total eurobonds ..............................   $  322,811   $  291,643
                                                      ==========   ==========

     Senior Notes and Sterling Bonds:
     6.853% Senior Notes, due 2004 ................   $  124,590   $  124,613
     6.995% Senior Notes, due 2007 ................      236,223      235,937
     7.25% Sterling Bonds, due 2022 ...............      316,829      285,950
                                                      ----------   ----------
     Total senior notes and sterling bonds ........   $  677,642   $  646,500
                                                      ==========   ==========

     Yorkshire:
     9.25% Eurobonds, due 2020 ....................   $  421,896   $  383,576
     7.25% Eurobonds, due 2028 ....................      342,539      311,427
     Variable Rate Reset Trust Securities, due 2020
       (5.04% at December 31, 2002) ...............      258,821      235,313
     8.08% Trust Securities, due 2038 .............      249,695      261,082
     6.496% Yankee Bonds, due 2008 ................      300,185      300,199
                                                      ----------   ----------
     Total Yorkshire Electric debt ................   $1,573,136   $1,491,597
                                                      ==========   ==========

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

The Yorkshire  Electric Debt prohibits  distributions to any of its stockholders
unless  certain  financial  ratios are met by  Yorkshire or the  long-term  debt
rating is above a prescribed level.

On February 15, 2005, the Yorkshire  Variable Rate Reset Trust Securities may be
remarketed by the  underwriter at a fixed rate of interest  through the maturity
date or, at a  floating  rate of  interest  for up to one year and then at fixed
rate of interest through 2020, or redeemed by Yorkshire.

Kern River Senior Notes and Construction Financing Facility
-----------------------------------------------------------

On August 13, 2001,  Kern River issued $510.0  million in debt  securities.  The
offering was in the form of $510.0  million of 15-year  amortizing  Senior Notes
bearing a fixed rate of interest of 6.676%. For the Senior Notes, $405.0 million
will be amortized  through June 2016,  with a final payment of $105.0 million to
be made on July 31, 2016. As of December 31, 2002, the balance of the Kern River
Senior Notes was $488.0.

On July 17, 2002, Kern River received  approval from the FERC to construct,  own
and operate the 2003 Expansion  Project.  The estimated cost of the expansion is
approximately  $1.2 billion and is being be financed with approximately 70% debt
and 30% equity,  consistent with Kern River's  original capital  structure,  the
application for the FERC approval described above and the limitations  contained
in the indenture for Kern River`s existing senior notes.

Construction is being  initially  funded with the proceeds of the $875.0 million
credit facility  entered into by Kern River on June 21, 2002, for  approximately
70% of the  projected  capitalized  costs of the  2003  Expansion  Project.  The
remaining  approximately  30% of the  capitalized  costs of the  2003  Expansion
Project is being funded with equity from the  Company.  As of December 31, 2002,
the  balance  of the Kern  River  construction  financing  facility  was  $789.9
million.

                                      -72-

<PAGE>

Northern Natural Gas Senior Notes
---------------------------------

The  components of Northern  Natural Gas' Senior Notes comprise the following at
December 31 (in thousands):

                                                          2002
                                                        ---------
             6.875% Senior Notes, due 2005 ..........   $ 100,000
             6.75% Senior Notes, due 2008 ...........     150,000
             7.00% Senior Notes, due 2011 ...........     250,000
             5.375% Senior Notes, due 2012 ..........     300,000
             Unamortized debt discount ..............        (594)
                                                        ---------
             Total Senior Notes .....................   $ 799,406
                                                        =========

Cordova Funding Senior Secured Bonds
------------------------------------

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

                                                     2002       2001
                                                   --------   --------
         8.64% Senior Secured Bonds, due 2019 ..   $ 93,001   $ 93,515
         8.79% Senior Secured Bonds, due 2019 ..     31,137     31,309
         9.07% Senior Secured Bonds, due 2019 ..     29,139     29,300
         8.48% Senior Secured Bonds, due 2019 ..     12,685     12,755
         8.82% Senior Secured Bonds, due 2019 ..     57,801     58,121
                                                   --------   --------
         Total Senior Secured Bonds ............   $223,763   $225,000
                                                   ========   ========

MEHC has guaranteed a specified portion of the final scheduled principal payment
on December 15, 2019 on the Cordova Funding Senior Secured Bonds in an amount up
to a  maximum  of $37.0  million.  MEHC also  provides  a debt  service  reserve
guarantee in an amount  equal to the  principal,  premium,  if any, and interest
payment due on the bonds on the next  scheduled  payment date which was equal to
$14.3 million at December 31, 2002.

Salton Sea Funding Corporation Series F Bonds
---------------------------------------------

Salton Sea  Funding  Corporation,  an indirect  wholly  owned  subsidiary  of CE
Generation,  had a debt balance of $491.7 million at December 31, 2002. Minerals
is one of several guarantors of the Salton Sea Funding  Corporation's debt. As a
result of a note  allocation  agreement,  Minerals is primarily  responsible for
$137.8  million of the 7.475%  Senior  Secured  Series F Bonds due  November 30,
2018.  MEHC has guaranteed a specified  portion of the scheduled debt service on
the Series F Bonds equal to this current  principal amount of $137.8 million and
associated interest.

Casecnan Notes and Bonds
------------------------

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

                                                               2002       2001
                                                             --------   --------
Casecnan notes and bonds:
Senior Secured Floating Rate Notes (FRNs), due in 2002 ...   $   --     $ 23,638
11.45% Senior Secured Series A Notes, due in 2005 ........    125,000    125,000
11.95% Senior Secured Series B Bonds, due in 2010 ........    162,925    171,500
                                                             --------   --------
Total Casecnan notes and bonds ...........................   $287,925   $320,138
                                                             ========   ========

The Casecnan  Notes and Bonds are subject to redemption at the Company's  option
as  provided  in the  Trust  Indenture.  The  Casecnan  Notes and Bonds are also
subject to mandatory redemption based on certain conditions.

                                      -73-
<PAGE>

Philippine Term Loans
---------------------

The  Export-Import  Bank of the United States ("Ex-Im Bank")  provided term loan
financing  for the  Company's  Mahanagdong  geothermal  power  project  of $92.8
million at a fixed rate of 6.92%.  The Overseas Private  Investment  Corporation
("OPIC") is providing  term loan  financing of $20.6 million at a fixed interest
rate of 7.6%. The loans have scheduled repayments through June 2007.

OPIC provided term loan financing for the Company's  Malitbog  geothermal  power
project  of $22.7  million  that was  fixed at an  interest  rate of  9.176%.  A
syndicate of international  commercial banks is providing term loan financing of
$40.9 million at a variable  interest rate based on LIBOR (3.84% at December 31,
2002). The loans have scheduled repayments through June 2005.

Ex-Im  provided term loan  financing for the Company's  Upper Mahiao  geothermal
power project of $63.1 million at a fixed interest rate of 5.95%. United Coconut
Planters  Bank of the  Philippines  is  providing  term loan  financing  of $5.0
million at a variable interest rate based on LIBOR (4.42% at December 31, 2002).
The loans have scheduled repayments through June 2006.

The Philippine term loans comprise the following at December 31 (in thousands):

                                                             2002       2001
                                                           --------   --------
Philippine term loans:
Mahanagdong Project 7.60% Term Loan, due 2007 ..........   $ 20,571   $ 25,143
Mahanagdong Project 6.92% Term Loan, due 2007 ..........     92,766    113,381
Malitbog Project Variable Rate Term Loan, due 2005
3.84% and 4.295%, respectively .........................     40,890     55,402
Malitbog Project 9.176% Term Loan, due 2006 ............     22,677     30,725
Upper Mahiao Project Variable Rate Term Loan, due 2003
4.42% and 5.130%, respectively .........................      5,000      6,111
Upper Mahiao Project 5.95% Term Loan, due 2006 .........     63,057     82,459
                                                           --------   --------
Total Philippine term loans ............................   $244,961   $313,221
                                                           ========   ========

HomeServices Senior Notes and Other
-----------------------------------

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

In addition to the senior  notes,  HomeServices'  has  outstanding  notes,  with
varying interest rates, totaling $4.0 million at December 31, 2002.

                                      -74-

<PAGE>

Annual Repayments of Debt
-------------------------

The  annual  repayments  of debt for the  years  beginning  January  1, 2003 and
thereafter are as follows (in thousands):
<TABLE>
<CAPTION>

                                                      2003      2004      2005      2006      2007    THEREAFTER       TOTAL
                                                    --------  --------  --------  --------  --------  -----------   -----------
<S>                                                 <C>       <C>       <C>       <C>       <C>       <C>           <C>
Parent, Subsidiary and Project loans:
  Parent Company Debt ............................  $215,000  $   --    $260,000  $   --    $550,000  $ 1,514,456   $ 2,539,456
  MidAmerican Funding Senior Notes and Bonds .....      --        --        --        --        --        700,000       700,000
  MidAmerican Energy Mortgage Bonds ..............   100,000    55,630    90,500      --        --         94,440       340,570
  MidAmerican Energy Pollution Control Bonds .....     5,727      --        --        --       1,000      149,018       155,745
  MidAmerican Energy Notes .......................      --        --        --     160,000      --        400,000       560,000
  Northern  Electric Eurobonds ...................      --        --     161,469      --        --        161,342       322,811
  CE Electric UK Senior Notes and Sterling Bonds .      --     124,590      --        --     236,223      316,829       677,642
  Yorkshire ......................................      --        --        --        --        --      1,573,136     1,573,136
  Kern River Senior Notes ........................    24,000    25,000    26,000    26,000    26,000      361,000       488,000
  Kern River Construction Financing Facility .....      --        --        --        --        --        789,916       789,916
  Northern Natural Gas Senior Notes ..............      --        --     100,000      --        --        699,406       799,406
  Cordova Funding Senior Secured Bonds ...........     9,000     8,100     7,875     4,500     4,162      190,126       223,763
  Salton Sea Funding Corporation Series F Bonds ..     1,405     1,757     1,756     1,827     1,055      129,989       137,789
  Casecnan Notes and Bonds .......................    41,468    49,360    54,752    36,015    37,730       68,600       287,925
  Philippine Term Loans ..........................    72,148    67,148    63,034    30,037    12,594         --         244,961
  HomeServices Senior Notes and Other ............     1,465     5,133     5,048     5,036     5,024       17,325        39,031
  Other, including fair value adjustments ........      --        --        --        --        --         (8,395)       (8,395)
                                                    --------  --------  --------  --------  --------  -----------   -----------
    Total parent, subsidiary and project loans ...  $470,213  $336,718  $770,434  $263,415  $873,788  $ 7,157,188   $ 9,871,756
                                                    ========  ========  ========  ========  ========  ===========   ===========
</TABLE>

Fair Value
----------

At   December   31,   2002,   the  Company  had   fixed-rate   long-term   debt,
Company-obligated  mandatorily  redeemable  preferred  securities  of subsidiary
trusts, and subsidiary-obligated  mandatorily redeemable preferred securities of
subsidiary  trusts of $11,683.2  million in  principal  amount and having a fair
value of $12,188.8 million.  In addition,  at December 31, 2002, the Company had
floating-rate  obligations of $425.1 million that expose the Company to the risk
of increased  interest expense in the event of increases in short-term  interest
rates.

11. INCOME TAXES

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

                                                                    MEHC
                            YEAR ENDED                          (PREDECESSOR)
                            DECEMBER 31,      MARCH 14, 2000    JANUARY 1, 2000
                    -----------------------     THROUGH           THROUGH
                      2002           2001    DECEMBER 31, 2000  MARCH 13, 2000
                    ---------     ---------  -----------------  ---------------

    Current:
      Federal ..    $  46,714     $  51,025       $ 17,387        $  9,147
      State ....       14,516         2,669         10,527          (1,886)
      Foreign ..       54,586        43,450         40,823          16,012
                    ---------     ---------       --------        --------
                      115,816        97,144         68,737          23,273
                    ---------     ---------       --------        --------
    Deferred:
      Federal ..    $  (7,073)    $ (14,004)      $(32,469)       $  1,854
      State ....       (9,675)         (342)        (1,933)            834
      Foreign ..          520       167,266         18,942           5,047
                    ---------     ---------       --------        --------
                      (16,228)      152,920        (15,460)          7,735
                    ---------     ---------       --------        --------
        Total ..    $  99,588     $ 250,064       $ 53,277        $ 31,008
                    =========     =========       ========        ========

                                      -75-

<PAGE>


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

                                                                                       MEHC
                                               YEAR ENDED                          (PREDECESSOR)
                                               DECEMBER 31,       MARCH 14, 2000     JANUARY 1, 2000
                                              --------------         THROUGH           THROUGH
                                              2002      2001     DECEMBER 31, 2000  MARCH 13, 2000
                                              ----      ----     -----------------  ----------------

<S>                                           <C>       <C>             <C>              <C>
Federal statutory rate .................      35.0%     35.0%           35.0%            35.0%
Investment and energy tax credits ......      (0.7)     (1.0)           (2.3)            (0.7)
State taxes, net of federal tax effect .       1.2       3.2             2.6             (0.8)
Goodwill amortization ..................       --        5.9            12.1              5.9
Dividends on preferred
  securities of subsidiary trusts ......      (8.1)     (6.1)          (11.1)            (2.8)
Tax effect of foreign income ...........      (4.8)     (2.5)           (5.8)            (5.0)
Non-recurring items on CE Electric UK,
  net of tax effect of foreign income ..      (8.1)     19.2             --               --
Dividends received deduction ...........      (1.8)     (2.6)           (6.8)            (1.0)
Other items, net .......................       2.8      (1.5)            0.6              3.4
                                              ----      ----            ----             ----
Effective tax rate .....................      15.5%     49.6%           24.3%            34.0%
                                              ====      ====            ====             ====
</TABLE>

Deferred tax  liabilities  (assets)  comprise  the  following at December 31 (in
thousands):

                                                        2002           2001
                                                     -----------    -----------

Properties, plants and equipment, net ............   $ 1,325,228    $ 1,133,286
Income taxes recoverable through future rates ....       159,411        185,222
Employee benefits ................................        65,537         68,514
Reacquired debt ..................................         4,914          7,544
Fuel cost recoveries .............................          --           20,272
Other ............................................           121           --
                                                     -----------    -----------
                                                       1,555,211      1,414,838
                                                     -----------    -----------

Minimum pension liability adjustment .............      (140,854)        (5,147)
Revenue sharing accruals .........................       (48,861)       (24,769)
Accruals not currently deductible for tax purposes       (59,083)       (47,287)
Nuclear reserve and decommissioning ..............       (28,411)       (17,898)
Deferred income ..................................       (21,733)       (24,732)
Fuel cost recoveries .............................        (9,558)          --
NOL and credit carryforwards .....................        (8,290)        (5,567)
Other ............................................          --           (5,170)
                                                     -----------    -----------
                                                        (316,790)      (130,570)
                                                     -----------    -----------
  Net deferred income taxes ......................   $ 1,238,421    $ 1,284,268
                                                     ===========    ===========
                                      -76-
<PAGE>

12. COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY
    TRUSTS

The  Company  has   organized   special   purpose   Delaware   business   trusts
(collectively,  the "Trusts")  pursuant to their respective amended and restated
declarations of trusts (collectively, the "Declarations").  The Company, through
these  Trusts,  issued   Company-obligated   mandatorily   redeemable  preferred
securities (collectively, the "Trust Securities") as follows (in thousands):
<TABLE>
<CAPTION>

                                                                           2002         2001
                                                                       -----------    ---------
<S>                                                                    <C>            <C>
CalEnergy Capital Trust II - 6.25% preferred securities, due 2012 ..   $   155,538    $ 155,584
CalEnergy Capital Trust III - 6.5% preferred securities, due 2027 ..       269,980      269,984
MidAmerican Capital Trust I - 11% preferred securities, due 2010 ...       454,772      454,772
MidAmerican Capital Trust II - 11% preferred securities, due 2012 ..       323,000         --
MidAmerican Capital Trust III - 11% preferred securities, due 2012 .       950,000         --
Fair value adjustment ..............................................       (89,878)     (92,189)
                                                                       -----------    ---------
Total Company-Obligated Mandatorily Redeemable Preferred Securities
  of Subsidiary Trusts .............................................   $ 2,063,412    $ 788,151
                                                                       ===========    =========
</TABLE>

The  Company  owns  all of  the  common  securities  of the  Trusts.  The  Trust
Securities  have a liquidation  preference  of $50 each and represent  undivided
beneficial  ownership  interests in each of the Trusts. The assets of the Trusts
consist  solely of the  Company's  Subordinated  Debentures  (collectively,  the
"Junior  Debentures")  issued  pursuant  to  their  respective  indentures.  The
indentures  include  agreements  by the Company to pay expenses and  obligations
incurred by the Trusts.

Prior to the Teton Transaction,  each Trust Security issued by CalEnergy Capital
Trust II and III with a par value of $50 was  convertible  at the  option of the
holder  at any time into  shares  of the  Company's  common  stock  based on the
conversion rate. As a result of the Teton Transaction,  in lieu of shares of the
Company's common stock, holders of Trust Securities will receive $35.05 for each
share of common stock it would have been entitled to receive on conversion.

Distributions  on the Trust  Securities (and Junior  Debentures) are cumulative,
accrue from the date of initial  issuance and are payable  quarterly in arrears.
The  Junior  Debentures  are  subordinated  in right of  payment  to all  senior
indebtedness  of the  Company and the Junior  Debentures  are subject to certain
covenants,  events of default and optional and mandatory redemption  provisions,
all as described in the Junior Debenture indentures.

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.

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

On March 11, 2002,  MidAmerican  Energy redeemed all $100.0 million of its 7.98%
MidAmerican-obligated  preferred  securities of subsidiary  trust at 100% of the
principal amount plus accrued interest.

14. PREFERRED SECURITIES OF SUBSIDIARIES

During 2002,  MidAmerican  Energy redeemed all $26.7 million of its $7.80 Series
Preferred Shares.

The total outstanding  cumulative preferred securities of MidAmerican Energy not
subject to mandatory  redemption  requirements  may be redeemed at the option of
MidAmerican Energy at prices which, in the aggregate,  total $32.6 million.  The
aggregate total the holders of all preferred securities  outstanding at December
31, 2002,  are entitled to upon  involuntary  bankruptcy  is $31.8  million plus
accrued  dividends.  Annual dividend  requirements for all preferred  securities
outstanding at December 31, 2002, total $1.3 million.

The total outstanding 8.061% cumulative  preferred securities of CE Electric UK,
which are redeemable in the event of the revocation by the Secretary of State of
the  Company's  Public  Electricity  Supply  License,  was $56.0  million  as of
December 31, 2002 and 2001.

                                      -77-
<PAGE>

15. CONVERTIBLE PREFERRED STOCK

In connection with the Kern River acquisition and the purchase of $275.0 million
of Williams'  preferred  stock, the Company issued 6.7 million shares of no par,
zero-coupon  convertible preferred stock valued at $402.0 million. In connection
with the Teton  Transaction,  the Company  issued 34.6 million shares of no par,
zero coupon convertible  preferred stock valued at $1,211.4 million.  Each share
of preferred  stock is convertible at the option of the holder into one share of
the Company's  common stock subject to certain  adjustments  as described in the
Company's Amended and Restated Articles of Incorporation.

16. STOCK OPTIONS

The Company had various  stock option plans under which shares were reserved for
grant as incentive or non-qualified stock options, as determined by the Board of
Directors.  The plans allowed  options to be granted at 85% of their fair market
value of the common stock at the date of grant.  Generally,  options were issued
at 100% of fair market value of the common  stock at the date of grant.  Options
remaining  subsequent to the Teton Transaction  became exercisable over a period
of two to five years and expired if not exercised within ten years from the date
of grant or, in some instances, a lesser term.

As a result of the Teton  Transaction,  the  majority of the options were cashed
out at $35.05 per share. The remaining  options of 2,145,000 were reissued under
the new MEHC and an additional  703,329 options were issued. The old options are
fully vested and the  additional  options  vest  monthly  over three years.  The
options are exercisable  until the end of the term on March 14, 2008 at exercise
prices ranging from $15.94 to $35.05 per share.

On March 6, 2002, the Company  purchased  stock options from Mr. David L. Sokol,
its Chairman and Chief  Executive  Officer.  The options  purchased had exercise
prices  ranging  from $18.50 to $29.01.  The Company paid Mr. Sokol an aggregate
amount of $27.1  million,  which is equal to the  difference  between the option
exercise prices and an agreed upon per share value.

17. ACCOUNTING FOR DERIVATIVES

MidAmerican Energy
------------------

Commodity Price Risk

Under the current regulatory framework, MidAmerican Energy is allowed to recover
in revenue the cost of gas sold from all of its regulated gas customers  through
a purchased gas adjustment clause.  Because the majority of MidAmerican Energy's
firm natural gas supply contracts contain pricing provisions based on a daily or
monthly market index,  MidAmerican  Energy's  regulated gas customers,  although
ensured of the  availability  of gas supplies,  retain the risk  associated with
market price volatility.

MidAmerican  Energy uses  natural  gas  futures,  options  and  over-the-counter
agreements  to mitigate a portion of the market risk  retained by its  regulated
gas customers  through the  purchased gas  adjustment  clause.  These  financial
derivative  instruments are identified and recorded as hedge  transactions.  The
net amounts exchanged or accrued under swap agreements and the realized gains or
losses on  futures  and  options  contracts  are  included  in cost of sales and
recovered in revenue from regulated gas customers.

MidAmerican  Energy also derives revenue from nonregulated sales of natural gas.
Pricing  provisions are  individually  negotiated  with these  customers and may
include fixed prices,  prices based on a daily or monthly market index or prices
based on  MidAmerican  Energy's  actual  costs.  MidAmerican  Energy enters into
natural gas futures,  options and swap agreements to offset the financial impact
of  variations  in  natural  gas  commodity  prices  for  physical  delivery  to
nonregulated customers.  These financial derivative activities are also recorded
as hedge accounting transactions.

MidAmerican  Energy is exposed to variations in the price of fuel for generation
and the  price of  purchased  power in its Iowa  jurisdiction,  which  comprises
approximately  89% of 2002  electric  operating  revenues.  Fuel  price  risk is
mitigated  through  forward  contracts.   Under  typical  operating  conditions,
MidAmerican  Energy has  sufficient  generation to supply its  regulated  retail
electric  needs. A loss of such generation at a time of high market prices could
subject  MidAmerican  Energy to losses on its energy sales.  MidAmerican  Energy
uses  electricity  forward  contracts  to  hedge  anticipated  sales  of  excess
wholesale electric power.

                                      -78-
<PAGE>

Derivative  instruments are used for two types of hedges. Hedges that offset the
variability in earnings and cash flows related to firm  commitments are referred
to as fair value hedges. Gains and losses on fair value hedges are recognized in
income as either operating revenues or cost of sales,  depending upon the nature
of the item being hedged.  Purchase and sales  commitments  hedged by fair value
hedges are recorded at fair value,  with changes in their fair values recognized
in income and substantially offsetting the impact of the hedges on earnings. For
2002, net pre-tax unrealized gains (losses), representing the ineffectiveness of
fair value hedges, were immaterial.

Hedges  that  offset the  variability  in  earnings  and cash  flows  related to
forecasted  transactions  are  referred to as cash flow  hedges.  The  effective
portion of unrealized  gains and losses on cash flow hedges is recorded in other
comprehensive  income, net of associated  deferred income taxes. Any ineffective
portion of  unrealized  gains and losses on cash flow  hedges is  recognized  in
income as operating  revenues or a cost of sales,  depending  upon the nature of
the item being hedged.  Only hedges that are highly  effective in offsetting the
risk of  variability  in future  cash flows are  accounted  for in this  manner.
Forecasted  transactions  include  purchases of gas for resale to regulated  and
nonregulated customers, purchases of gas for storage, and purchases and sales of
wholesale  electric energy.  When the associated hedged  forecasted  transaction
occurs or if a hedging  relationship  is no longer  appropriate,  the unrealized
gains and losses are reversed from other comprehensive  income and recognized in
net  income.  Realized  gains on cash flow  hedges are  recognized  in income as
either  operating  revenues or cost of sales,  depending  upon the nature of the
physical transaction being hedged.

For 2002,  net  pre-tax  unrealized  gains  (losses)  of $13,000  and  $502,000,
representing the ineffectiveness of cash flow hedges, are reflected in operating
revenues and cost of sales,  respectively,  on the  consolidated  statements  of
operations.   During  the  twelve  months  beginning  January  1,  2003,  it  is
anticipated that all of the after-tax,  net unrealized gains on cash flow hedges
presently  recorded as accumulated other  comprehensive  income will be realized
and  recorded  in  earnings.  MidAmerican  Energy  has  hedged a portion  of its
exposure to the  variability of cash flows for forecasted  transactions  through
December 2003.

At December 31, 2002,  MidAmerican  Energy held derivative  instruments used for
the following hedging purposes with the following fair values (in thousands):

                                    Maturity   Maturity in
               Type                 in 2003      2004-06     Total
               ----                 --------   -----------   ------
             Regulated electric      $1,018      $ 112       $1,130
             Regulated gas ....       1,150       --          1,150
             Nonregulated gas .       2,027        (41)       1,986
                                     ------      -----       ------
                  Total .......      $4,195      $  71       $4,266
                                     ======      =====       ======

A $5.00 per MWh  increase in the price of  electricity  would  decrease the fair
value of electric hedge  instruments by $316,000.  A $1.00 per MMBtu increase in
the price of natural gas would increase the fair value of gas hedge  instruments
by $2.3 million.

Trading Risk

MidAmerican Energy uses natural gas and electricity  derivative  instruments and
forward  contracts for  proprietary  trading  purposes  under strict  guidelines
outlined by senior management.  Derivative instruments held for trading purposes
are  recorded at fair value and any  unrealized  gains or losses are reported in
earnings.

                                      -79-

<PAGE>

MidAmerican  Energy  uses value at risk,  or VaR  calculations  to  measure  and
control its exposure to market risk sensitive instruments. VaR is an estimate of
the potential  loss on a portfolio  over a specified  holding  period,  based on
normal market  conditions and within a given  statistical  confidence  interval.
MidAmerican   Energy   calculates  VaR  separately  for  its  electric  and  gas
proprietary  trading  activities  based on a  variance-covariance  method  using
historical prices to estimate  volatilities and correlations,  a one-day holding
period  and  a  95%  level  of  confidence.  MidAmerican  Energy  initiated  its
nonregulated proprietary electric trading activities in early 2002. Accordingly,
the  following  summary of  MidAmerican  Energy's  trading  VaR profile for 2001
includes only gas trading data.

                                                 VaR (in $millions)
                                                 2002         2001
                                                 ----         ----
         At December 31......................    $0.3         $0.2
         High during year....................     0.5          0.3
         Low during year.....................     0.1          -
         Average during year.................     0.2          0.1

The  fair  value of  MidAmerican  Energy's  proprietary  trading  activities  at
December  31,  2002 and the  periods  in which  unrealized  gains and losses are
expected to be realized are as follows (in thousands):

                                   Maturity in   Maturity in
         Type                         2003         2004-06      Total
         ----                      -----------   -----------   -------
         Exchange prices .......     $ 4,683       $  71       $ 4,754
         Prices actively quoted.      (4,259)       (159)       (4,418)
         Prices based on models.         207         (14)          193
                                     -------       -----       -------
              Total ............     $   631       $(102)      $   529
                                     =======       =====       =======

CE Electric UK
--------------

Currency Exchange Rate Risk

CE Electric UK entered into certain  currency  rate swap  agreements  for the CE
Electric  UK  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  $125.0  million of 6.853%
Senior  Notes,  the  agreements  extend until  maturity on December 30, 2004 and
convert the U.S.  dollar  interest rate to a fixed Sterling rate of 7.744%.  For
the $237.0 million of 6.995% Senior Notes, the agreements  extend until maturity
on  December  30,  2007 and convert  the U.S.  dollar  interest  rate to a fixed
Sterling rate of 7.737%.  The estimated  fair value of these swap  agreements at
December  31,  2002 is  approximately  $24.5  million  based on quotes  from the
counterparty to these  instruments and represents the estimated  amount that the
Company would expect to receive if these agreements were terminated.

Yorkshire  entered  into certain  currency  rate swap  agreements  for the Trust
Securities  and the  Yankee  Bonds  with  five  large  multi-national  financial
institutions.  The swap  agreements  effectively  convert the U.S.  dollar fixed
interest rate to a fixed rate in Sterling.  For the 8.08% Trust Securities,  the
agreements  extend until June 30, 2008 and convert the U.S. dollar interest rate
to a fixed Sterling rate ranging from 9.4758% to 9.715%.  For the $300.0 million
of 6.496%  Yankee  Bonds,  the  agreements  extend  until  February 25, 2008 and
convert the U.S.  dollar  interest  rate to a fixed  Sterling  rate ranging from
7.3175% to 7.345%. The estimated fair value of these swap agreements at December
31, 2002 is approximately  $(22.8) million based on quotes from the counterparty
to these  instruments and represents the estimated amount that the Company would
expect to pay if these agreements were terminated.

A decrease  of 10% in the  December  31,  2002 rate of  exchange  of Sterling to
dollars would  increase the amount paid to the Company if these swap  agreements
were terminated by approximately $120.9 million.

                                      -80-

<PAGE>


Northern Natural Gas
--------------------

Commodity Price Risk

As of December 31, 2002,  Northern  Natural Gas had $52.0 million of obligations
to deliver 12.2 Bcf of natural gas in 2003. The  obligations  are revalued based
on market  prices  for  natural  gas,  with  changes  in value  included  in the
statement of operations.  In 2002, Northern Natural Gas entered into natural gas
commodity  price  swaps and index basis swaps to  effectively  fix the  deferred
obligation balance. These swaps have a net receivable balance of $3.4 million at
December 31, 2002.  The swaps are  revalued  based on market  prices for natural
gas, with changes in value included in the statement of  operations.  Therefore,
any further changes in the market value of the deferred obligations are expected
to be offset by a corresponding  change in the opposite  direction in the market
value of the swaps.  However,  at December 31, 2002,  Northern Natural Gas had a
$10.4 million receivable position with a third party energy marketer relating to
these swaps. Since the date of entering into these swaps, there have been public
announcements that this third party's financial  condition has deteriorated as a
result of,  among  other  factors,  reduced  liquidity.  This  receivable  would
increase by  approximately  $12.2 million if the price curve of natural gas were
to increase by $1.00 per MMBtu from levels at December 31, 2002. The Company has
not  recorded an allowance on this  receivable  as of December 31, 2002,  and is
monitoring the situation.

18. REGULATORY MATTERS

MidAmerican Energy
------------------

Under  a  settlement  agreement  approved  by the  IUB  on  December  21,  2001,
MidAmerican  Energy's Iowa retail electric rates in effect on December 31, 2000,
are effectively  frozen through December 31, 2005. In approving that settlement,
the IUB  specifically  allows the filing of electric  rate design and/or cost of
service  rate  changes  that  are  intended  to keep  overall  company  revenues
unchanged  but could  result in changes to  individual  tariffs.  Under the 2001
settlement  agreement,  an amount equal to 50% of revenues  associated with Iowa
retail  electric  returns on equity  between 12% and 14%, and 83.33% of revenues
associated with Iowa retail  electric  returns on equity above 14%, in each year
is recorded as a regulatory liability to be used to offset a portion of the cost
to Iowa customers of future generating plant investments. An amount equal to the
regulatory  liability is recorded as a  regulatory  charge in  depreciation  and
amortization expense when the liability is accrued.  Interest expense is accrued
on the portion of the regulatory liability related to prior years.  Beginning in
2002,  the liability is being relieved as it is credited  against  allowance for
funds used during construction,  or capitalized financing costs, associated with
generating  plant  additions.  As of December  31, 2002,  the related  liability
reflected on the consolidated balance sheet totaled $102.9 million.

On March 20, 2003,  MidAmerican  Energy and the Iowa Office of Consumer Advocate
agreed upon a settlement proposal in which the rate freeze described above would
be extended  through  December  31, 2010.  Under the  settlement  proposal,  for
calendar years 2006 through 2010, an amount equal to 40% of revenues  associated
with Iowa retail  electric  returns on equity between  11.75% and 13.0%;  50% of
revenues  associated with Iowa retail  electric  returns on equity between 13.0%
and 14.0%; and 83.3% of revenues associated with Iowa retail electric returns on
equity  greater  than 14.0% will be applied as a reduction to offset some of the
capital costs on the Iowa portion of three generation  projects.  If Iowa retail
electric  returns on equity fall below 10% in any 12-month  period after January
1, 2006,  MidAmerican  Energy has the ability to file for a general  increase in
rates under the proposed settlement.  The proposed settlement requires enactment
of Iowa  legislation  and is subject to approval by the IUB. The IUB is expected
to rule on the proposal during the second half of 2003.

On March 15, 2002,  MidAmerican  Energy made a filing with the IUB requesting an
increase in rates for its Iowa retail natural gas  customers.  On June 12, 2002,
the IUB issued an order granting an interim rate increase of approximately $13.8
million annually,  effective immediately and subject to refund with interest. On
November 8, 2002, the IUB approved the proposed settlement  agreement previously
filed with it by  MidAmerican  Energy and the Iowa Office of Consumer  Advocate.
The  settlement  agreement  provides  for an increase in rates of $17.7  million
annually  for  MidAmerican  Energy's  Iowa  retail  natural  gas  customers  and
effectively  freezes  such  rates  through  November  2004.  MidAmerican  Energy
implemented the new rates for usage beginning November 25, 2002.

CE Electric UK
--------------

Most revenue of each  Distribution  License  Holder  ("DLH") is  controlled by a
distribution price control formula.  The current formula requires that regulated
distribution income per unit is increased or decreased each year by RPI-Xd where
the Retail Price Index  ("RPI")  reflects the average of the 12-month  inflation
rates  recorded  for each month in the  previous  July to December  period.  The
distribution  price control  formula also  reflects an adjustment  factor ("Xd")
which was established

                                      -81-
<PAGE>

by the regulatory body, the Office of Gas and Electricity Markets ("Ofgem"),  at
the last price control  review (and continues to be set) at 3%. The formula also
takes  account  of the  changes  in  system  electrical  losses,  the  number of
customers  connected  and the  voltage at which  customers  receive the units of
electricity  distributed.  This formula determines the maximum average price per
unit of  electricity  distributed  (in pence per kWh) which a DLH is entitled to
charge.   The  distribution  price  control  formula  permits  DLHs  to  receive
additional  revenue due to increased  distribution  of units and a predetermined
increase in customer  numbers.  The price control does not seek to constrain the
profits of a DLH from year to year.  It is a control on  revenue  that  operates
independently  of most of the DLH's  costs.  During  the  lifetime  of the price
control, cost savings or additional costs have a direct impact on profit.

19. PENSION COMMITMENTS

Domestic Operations
-------------------

The Company has primarily noncontributory defined benefit pension plans covering
substantially all domestic  employees.  Benefit  obligations under the plans are
based on  participants'  compensation,  years of service and age at  retirement.
Funding  is based  upon the  actuarially  determined  costs of the plans and the
requirements  of the Internal  Revenue Code and the Employee  Retirement  Income
Security Act.

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

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

                                      -82-

<PAGE>

Net periodic pension,  supplemental  retirement and postretirement benefit costs
for domestic employees included the following components for the Company:
<TABLE>
<CAPTION>

                                                                                               MEHC
                                                   YEAR ENDED                              (PREDECESSOR)
                                                   DECEMBER 31,        MARCH 14, 2000      JANUARY 1, 2000
                                              ----------------------      THROUGH             THROUGH
                                                2002          2001     DECEMBER 31, 2000   MARCH 13, 2000
                                              --------      --------   -----------------   ---------------
<S>                                            <C>            <C>            <C>            <C>
Pension Cost:
  Service cost ............................      $ 20,235       $ 18,114       $ 13,014       $ 3,242
  Interest cost ...........................        34,177         33,027         28,329         7,058
  Expected return on plan assets ..........       (38,213)       (36,326)       (38,532)       (9,600)
  Amortization of net transition obligation        (2,591)        (2,591)        (2,074)         (517)
  Amortization of prior service cost ......         2,729          2,729          2,310           575
  Amortization of prior year gain .........        (2,482)        (3,894)        (3,297)         (822)
  Regulatory expense ......................         6,639           --             --            --
                                                 --------       --------       --------       -------
    Net periodic pension cost (benefit) ...      $ 20,494       $ 11,059       $   (250)      $   (64)
                                                 ========       ========       ========       =======
</TABLE>
<TABLE>
<CAPTION>

                                                                                                MEHC
                                                   YEAR ENDED                              (PREDECESSOR)
                                                   DECEMBER 31,        MARCH 14, 2000      JANUARY 1, 2000
                                              ----------------------      THROUGH             THROUGH
                                                2002          2001     DECEMBER 31, 2000   MARCH 13, 2000
                                              --------      --------   -----------------   ---------------
<S>                                              <C>            <C>    <C>    <C>    <C>    <C>
Postretirement Cost:
  Service cost ............................      $  6,028       $  4,357       $  2,089       $   520
  Interest cost ...........................        13,928         10,418          6,688         1,666
  Expected return on plan assets ..........        (4,880)        (4,032)        (3,947)         (984)
  Amortization of net transition obligation         4,110          4,110          3,290           820
  Amortization of prior service cost ......           425            425            340            85
  Amortization of prior year (gain) loss ..         2,385            332           (699)         (174)
                                                 --------       --------       --------       -------
    Net periodic pension cost .............      $ 21,996       $ 15,610       $  7,761       $ 1,933
                                                 ========       ========       ========       =======
</TABLE>

The pension  plan assets are in external  trusts and are  comprised of corporate
equity securities,  United States government debt, corporate bonds and insurance
contracts.  The  postretirement  benefit plans assets are in external trusts and
are comprised  primarily of corporate equity securities,  corporate bonds, money
market investment accounts and municipal bonds.

Although the  supplemental  executive  retirement plans had no plan assets as of
December   31,   2002,   MidAmerican   Energy  has  Rabbi   trusts   which  hold
corporate-owned  life insurance and other investments to provide funding for the
future cash requirements.  Because these plans are nonqualified,  the fair value
of these assets is not included in the  following  table.  The fair value of the
Rabbi trust investments was $52.8 million and $50.4 million at December 31, 2002
and 2001, respectively.

                                      -83-

<PAGE>

The  following  table  presents a  reconciliation  of the  beginning  and ending
balances  of the  benefit  obligation,  fair value of plan assets and the funded
status of the Company's plans to the net amounts  recognized in the consolidated
balance sheet as of December 31 (dollars in thousands):

<TABLE>
<CAPTION>

                                                                    PENSION                POSTRETIREMENT
                                                                    BENEFITS                  BENEFITS
                                                              ----------------------    ----------------------
                                                                2002         2001         2002         2001
                                                              ---------    ---------    ---------    ---------
<S>                                                           <C>          <C>          <C>          <C>
Reconciliation of benefit obligation:
  Benefit obligation at beginning of year .................   $ 518,208    $ 472,349    $ 194,917    $ 131,822
  Service cost ............................................      20,235       18,114        6,028        4,357
  Interest cost ...........................................      34,177       33,027       13,928       10,418
  Participant contributions ...............................        --           --          4,505        3,059
  Plan amendments .........................................        --            652         --           --
  Actuarial (gain) loss ...................................      45,461       17,333       31,743       57,101
  Acquisition .............................................         520         --         55,305         --
  Benefits paid ...........................................     (25,422)     (23,267)     (14,985)     (11,840)
                                                              ---------    ---------    ---------    ---------
    Benefit obligation at end of year .....................     593,179      518,208      291,441      194,917
                                                              ---------    ---------    ---------    ---------

Reconciliation of the fair value of plan assets:
  Fair value of plan assets at beginning of year ..........     515,890      555,208       81,129       75,090
  Employer contributions ..................................       4,681        4,576       24,034       16,022
  Participant contributions ...............................        --           --          4,505        3,059
  Actual return on plan assets ............................     (27,376)     (20,627)      (4,528)      (1,202)
  Acquisition .............................................        --           --         32,500         --
  Benefits paid ...........................................     (25,422)     (23,267)     (14,985)     (11,840)
                                                              ---------    ---------    ---------    ---------
    Fair value of plan assets at end of year ..............     467,773      515,890      122,655       81,129
                                                              ---------    ---------    ---------    ---------

  Funded status ...........................................    (125,406)      (2,318)    (168,786)    (113,788)
  Unrecognized net (gain) loss ............................      61,289      (52,244)     102,095       63,328
  Unrecognized prior service cost .........................      20,156       22,885        3,838        4,264
  Unrecognized net transition obligation (asset) ..........      (3,383)      (5,974)      41,102       45,212
                                                              ---------    ---------    ---------    ---------
    Net amount recognized in the consolidated balance sheet   $ (47,344)   $ (37,651)   $ (21,751)   $    (984)
                                                              =========    =========    =========    =========

Amounts recognized in the consolidated balance sheet
  consist of:
  Prepaid benefit cost ....................................   $  11,305    $  15,381    $   1,494    $   1,493
  Accrued benefit liability ...............................     (99,392)     (88,210)     (23,245)      (2,477)
  Intangible asset ........................................      20,082       22,796         --           --
  Accumulated other comprehensive income ..................      20,661       12,382         --           --
                                                              ---------    ---------    ---------    ---------
  Net amount recognized ...................................   $ (47,344)   $ (37,651)   $ (21,751)   $    (984)
                                                              =========    =========    =========    =========
</TABLE>
                                      -84-
<PAGE>

Pension  and  Postretirement  Assumptions  are as  follows  for the years  ended
December 31:

                                                     2002       2001       2000
                                                     ----       ----       ----
Assumptions used were:
Discount rate .................................      5.75%      6.50%      7.00%
Rate of increase in compensation levels .......      5.00%      5.00%      5.00%
Weighted average expected long-term rate
  of return on assets .........................      7.00%      7.00%      9.00%


For purposes of calculating the postretirement benefit obligation, it is assumed
health care costs for all covered individuals will increase by 9.75% in 2003 and
that the rate of increase  thereafter will decrease to an ultimate rate of 5.25%
by the year 2007.

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 2002 would  increase by $4.1 million,  and the  postretirement
benefit obligation at December 31, 2002, would increase by $47.5 million. If the
assumed  health care trend rates were to decrease by 1.0%, the total service and
interest  cost for 2002 would  decrease by $3.1  million and the  postretirement
benefit obligation at December 31, 2002, would decrease by $37.0 million.

United Kingdom Operations
-------------------------

CE Electric UK  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, 2002, 2001 and 2000 assumed interest
rates of 5.75%, 5.75% and 6.0%  respectively,  an expected return on plan assets
of 7.0%, 7.0% and 6.5%, respectively, and annual compensation increases of 2.5%,
2.5% and 3.0%,  respectively,  over the  remaining  service  lives of  employees
covered under the plan.  Amounts funded to the pension are primarily invested in
equity and fixed income securities.

Net periodic pension cost (benefit) for CE Electric UK's plan for 2002, 2001 and
2000 included the following  components (in  thousands):
<TABLE>
<CAPTION>

                                                                                                     MEHC
                                                        YEAR ENDED                               (PREDECESSOR)
                                                        DECEMBER 31,          MARCH 14, 2000    JANUARY 1, 2000
                                                     ----------------------     THROUGH            THROUGH
                                                       2002          2001    DECEMBER 31, 2000  MARCH 13, 2000
                                                     --------      --------  -----------------  ---------------

<S>                                                  <C>           <C>           <C>               <C>
Service cost - benefits earned during the period     $  8,718      $  7,781      $  6,933          $  1,727
Interest cost on projected benefit obligation ..       56,817        51,440        40,640            10,125
Expected return on plan assets .................      (85,927)      (78,354)      (50,800)          (12,657)
Amortization of prior service cost .............        1,202          --            --                --
Curtailment loss ...............................        6,463         7,061         5,260             1,310
                                                     --------      --------      --------          --------
Net periodic pension (benefit) cost ............     $(12,727)     $(12,072)     $  2,033          $    505
                                                     ========      ========      ========          ========
</TABLE>

As a  result  of  the  distribution  price  reviews  in  1999,  CE  Electric  UK
implemented  a review of staffing  requirements  primarily  in its  distribution
business.  Following  discussions  with the trade unions,  CE Electric UK put in
place a workforce  reduction program.  The pension  curtailment  related to this
workforce  reduction program was $6.9 million,  $7.1 million and $6.6 million in
2002, 2001 and 2000, respectively.

                                      -85-

<PAGE>

The following  table details the funded status and the amount  recognized in the
Company's  consolidated  balance sheets for CE Electric UK's plan as of December
31, 2002 and 2001 (in thousands):
<TABLE>
<CAPTION>

                                                                      2002           2001
                                                                   -----------    -----------
<S>                                                                <C>            <C>
Change in benefit obligation:
Benefit obligation at beginning of year ........................   $   974,079    $   951,553
Service cost ...................................................         8,718          7,781
Interest cost ..................................................        56,817         51,440
Participant contributions ......................................         3,006          5,187
Benefits paid ..................................................       (57,719)       (48,991)
FAS 88 curtailment .............................................         5,712          7,060
Northern Supply/Yorkshire swap net effect ......................          --           43,803
Prior service cost .............................................        17,286           --
Experience gain and change of assumptions ......................       (11,574)       (19,596)
Foreign currency exchange rate changes .........................       106,405        (24,158)
                                                                   -----------    -----------
Benefit obligation at end of the year ..........................     1,102,730        974,079
                                                                   -----------    -----------

Change in plan assets:
Fair value of plan assets at beginning of the year .............     1,070,657      1,166,111
Actual return on plan assets ...................................      (144,298)       (68,010)
Net asset transfer resulting from Northern Supply/Yorkshire
    Swap .......................................................          --           46,541
Employer contributions .........................................         3,607            576
Participant contributions ......................................         3,006          5,187
Benefits paid ..................................................       (57,719)       (48,991)
Foreign currency exchange rate changes .........................       101,174        (30,757)
                                                                   -----------    -----------
Fair value of plan assets at end of the year ...................       976,427      1,070,657
                                                                   -----------    -----------
Funded status ..................................................      (126,303)        96,578
Unrecognized net loss ..........................................       465,211        196,649
                                                                   -----------    -----------
Net amount recognized in the consolidated balance sheet ........   $   338,908    $   293,227
                                                                   ===========    ===========

Amounts recognized in the consolidated balance sheet consist of:
Prepaid benefit cost ...........................................   $   338,908    $   293,227
Accrued benefit liability ......................................      (457,317)          --
Intangible asset ...............................................        16,433           --
Accumulated other comprehensive income .........................       440,884           --
                                                                   -----------    -----------
Net amount recognized ..........................................   $   338,908    $   293,227
                                                                   ===========    ===========
</TABLE>

                                      -86-

<PAGE>

20. COMMITMENTS AND CONTINGENCIES

Manufactured Gas Plants
-----------------------

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

MidAmerican  Energy has evaluated or is  evaluating 27 properties  that were, at
one time,  sites of gas  manufacturing  plants in which it may be a  potentially
responsible  party.  The purpose of these  evaluations  is to determine  whether
waste materials are present,  whether the materials  constitute an environmental
or health  risk,  and  whether  MidAmerican  Energy has any  responsibility  for
remedial action. As of December 31, 2002,  MidAmerican Energy has recorded a $17
million  liability  for these  sites and a  corresponding  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
MidAmerican Energy's financial position or results of operations.

Air Quality
-----------

In July 1997,  the EPA adopted  revisions  to the  National  Ambient Air Quality
Standards for ozone and a new standard for fine particulate  matter. In February
2001,  the United  States  Supreme  Court  upheld the  constitutionality  of the
standards, though remanding the issue of implementation of the ozone standard to
the EPA.  The impact of the new  standards  on  MidAmerican  Energy is currently
unknown. These standards could be superceded,  in whole or in part, by a variety
of multi-pollutant emission reduction initiatives.

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

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

The Plan  outlines  $732.0  million in  environmental  investments  to  existing
coal-fired  generating  units, some of which are jointly owned, over a nine-year
period from 2002 through 2010.  MidAmerican  Energy's share of these investments
is $546.6  million,  $67.9  million of which was projected to be incurred in the
years 2002 through 2005,  when  MidAmerican  Energy's Iowa retail electric rates
are effectively  frozen. The Plan also identifies expenses that will be incurred
at the generating facilities to operate and maintain the environmental equipment
installed as a result of the Plan.

Following the expiration of MidAmerican  Energy's 2001  settlement  agreement on
December 31, 2005,  the Plan  proposes the use of an  adjustment  mechanism  for
recovery of Plan costs,  similar to the tracking mechanisms for cost recovery of
renewable energy and energy  efficiency  expenditures that are presently part of
MidAmerican Energy's regulated electric rates.

Under the New Source Review ("NSR"),  provisions of the Clean Air Act ("CAA"), a
utility  is  required  to obtain a permit  from the EPA  prior to (1)  beginning
construction of a new major  stationary  source of a NSR-regulated  pollutant or
(2) making a  physical  or  operational  change (a "major  modification")  to an
existing facility that potentially  increases emissions,  unless the changes are
exempt under the  regulations.  In general,  projects subject to NSR regulations
are subject to  pre-construction  review and permitting  under the Prevention of
Significant Deterioration ("PSD"), provisions of the CAA. Under the PSD program,
a project that emits  threshold  levels of regulated  pollutants  must undergo a
Best  Available  Control  Technology  analysis and  evaluate the most  effective
emissions  controls.  These  controls  must be  installed  in order to receive a
permit.  Routine maintenance,  repair and replacement are not subject to the NSR
provisions; however, these types of activities have historically been subject to
changing  interpretations  under the NSR program.  The EPA  recently  proposed a
change  to the NSR  provisions  relating  to  routine  maintenance,  repair  and

                                      -87-
<PAGE>

replacement.  Violation  of NSR  regulations  potentially  subjects a utility to
fines  and/or other  sanctions.  The impact on  MidAmerican  Energy of any final
rules is not currently known.

In recent years,  the EPA has requested from several  utilities  information and
support  regarding their capital  projects for various  generating  plants.  The
requests  were  issued  as  part of an  industry-wide  investigation  to  assess
compliance with the NSR and the New Source Performance  Standards of the CAA. In
December  2002,  MidAmerican  Energy  received a request from the EPA to provide
documentation  related to its  capital  projects  from  January 1, 1980,  to the
present for its Neal,  Council  Bluffs,  Louisa and  Riverside  Energy  Centers.
MidAmerican Energy has responded to this request and at this time cannot predict
the outcome of request.

Decommissioning Costs
---------------------

Expected decommissioning costs for Quad Cities Station have been developed based
on  a  site-specific   decommissioning  study  that  includes   decontamination,
dismantling,  site  restoration,  dry fuel storage cost and an assumed  shutdown
date. Quad Cities Station decommissioning costs are included in as base rates in
Iowa tariffs.

MidAmerican  Energy's  share of expected  decommissioning  costs for Quad Cities
Station,  in 2002 dollars,  is $266 million.  MidAmerican Energy has established
external trusts for the investment of funds for  decommissioning the Quad Cities
Station.  The total accrued  balance as of December 31, 2002, was $159.8 million
and is included in other liabilities.  A like amount is reflected in properties,
plants and  equipment  and  represents  the fair value of the assets held in the
trusts.

MidAmerican Energy's depreciation expense included costs for Quad Cities Station
nuclear  decommissioning  of $8.3  million for each of the years 2002,  2001 and
2000. The provision charged to depreciation expense is equal to the funding that
is being  collected  in Iowa rates.  The  decommissioning  funding  component of
MidAmerican Energy's Iowa tariff 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%.  Income  (loss),  net of investment
fees, on the assets in the trust fund increase/(decrease) by a comparable amount
MidAmerican  Energy's  decommissioning  liability.  Actual  amounts  were $(6.9)
million, $(3.1) million and $3.2 million for 2002, 2001 and 2000, respectively.

Nuclear Insurance
-----------------

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

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

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

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

                                      -88-
<PAGE>

Fuel, Energy and Operating Lease Commitments
--------------------------------------------

MidAmerican  Energy has  supply and  related  transportation  contracts  for its
fossil fueled generating stations. The contracts,  with expiration dates ranging
from 2003 to 2007,  require  minimum  payments of $76.4 million,  $61.2 million,
$43.6  million,  $2.6 million and $2.6 million for the years 2003 through  2007,
respectively. MidAmerican Energy expects to supplement these coal contracts with
additional contracts and spot market purchases to fulfill its future fossil fuel
needs.

MidAmerican Energy also has contracts with non-affiliated  companies to purchase
electric  capacity.  The contracts,  with expiration  dates ranging from 2003 to
2028,  require minimum payments of $40.2 million,  $37.8 million,  $2.9 million,
$2.2 million and $2.2 million for the years 2003 through 2007, respectively, and
$45.6 million for the total of the years thereafter.

MidAmerican Energy has various natural gas supply and  transportation  contracts
for its gas operations.  The minimum commitments under these contracts are $51.9
million,  $46.8 million,  $37.2 million, $13.1 million and $10.2 million for the
years 2003 through  2007,  respectively,  and $16.6 million for the total of the
years thereafter.

HomeServices  is the lessee on operating  leases  primarily for office space for
its various brokerage offices. The minimum payments under these leases are $36.0
million,  $30.1 million,  $25.7 million, $22.4 million and $17.9 million for the
years 2003 through  2007,  respectively,  and $40.7 million for the total of the
years thereafter.

MidAmerican  Energy,  Kern River,  Northern  Natural Gas and CE Electric UK have
various  non-cancellable  operating  leases  primarily for office space and rail
cars. The minimum payments under these leases are $24.8 million,  $16.9 million,
$12.7  million,  $10.6 million and $9.4 million for the years 2003 through 2007,
respectively, and $46.0 million for the total of the years thereafter.

MidAmerican  Energy is the lessee on  operating  leases for coal  railcars  that
contain  guarantees of the residual value of such equipment  throughout the term
of the leases.  Events triggering the residual guarantees include termination of
the lease,  loss of the equipment or purchase of the equipment.  Lease terms are
for five years with provisions for extensions. At December 31, 2002, the maximum
amount of such guarantees specified in these leases totals $31.5 million.

Pipeline Litigation
-------------------

In 1998,  the United  States  Department  of Justice  informed  the then current
owners of Kern River and Northern Natural Gas that Jack Grynberg, an individual,
had filed  claims in the  United  States  District  Court  for the  District  of
Colorado  under the False Claims Act against such  entities and certain of their
subsidiaries  including  Kern River and Northern  Natural Gas. Mr.  Grynberg has
also filed claims against  numerous other energy  companies and alleges that the
defendants  violated the False Claims Act in connection with the measurement and
purchase  of  hydrocarbons.  The  relief  sought  is an  unspecified  amount  of
royalties  allegedly not paid to the federal government,  treble damages,  civil
penalties,  attorneys'  fees and  costs.  On April 9, 1999,  the  United  States
Department  of Justice  announced  that it declined to  intervene  in any of the
Grynberg  qui tam cases,  including  the actions  filed  against  Kern River and
Northern  Natural Gas in the United  States  District  Court for the District of
Colorado.   On  October  21,  1999,  the  Panel  on  Multi-District   Litigation
transferred  the Grynberg qui tam cases,  including  the ones filed against Kern
River and Northern  Natural  Gas, to the United  States  District  Court for the
District of Wyoming for pre-trial  purposes.  Motions to dismiss the  complaint,
filed by various defendants  including Northern Natural Gas and Williams,  which
was the former owner of Kern River,  were denied on May 18, 2001.  On October 9,
2002,  the United States  District  Court for the District of Wyoming  dismissed
Grynberg's Royalty Valuation Claims. Grynberg has appealed this dismissal to the
United States Court of Appeals for the Tenth  Circuit.  In  connection  with the
purchase of Kern River from Williams in March 2002, Williams agreed to indemnify
the Company against any liability for this claim;  however,  no assurance can be
given as to the  ability of  Williams  to perform  on this  indemnity  should it
become necessary.  No such  indemnification  was obtained in connection with the
purchase of Northern  Natural Gas in August 2002. The Company  believes that the
Grynberg  cases filed  against Kern River and  Northern  Natural Gas are without
merit and Williams, on behalf of Kern River pursuant to its indemnification, and
Northern Natural Gas, intend to defend these actions vigorously.

On June 8, 2001, a number of interstate pipeline companies, including Kern River
and Northern  Natural Gas, were named as defendants in a nationwide class action
lawsuit which had been pending in the 26th Judicial District, District Court,

                                      -89-
<PAGE>

Stevens County Kansas,  Civil  Department  against other  defendants,  generally
pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that
the  defendants  have  engaged in  mismeasurement  techniques  that  distort the
heating  content  of  natural  gas,  resulting  in an  alleged  underpayment  of
royalties to the class of producer plaintiffs.  In November 2001, Kern River and
Northern Natural Gas, along with the coordinating defendants,  filed a motion to
dismiss  under  Rules 9B and 12B of the  Kansas  Rules of  Civil  Procedure.  In
January 2002, Kern River and most of the coordinating  defendants filed a motion
to dismiss for lack of personal jurisdiction. The court has yet to rule on these
motions.  The  plaintiffs  filed for  certification  of the  plaintiff  class on
September  16,  2002.  On  January  13,  2003,  oral  arguments  were  heard  on
coordinating defendants' opposition to class certification.  Williams has agreed
to indemnify the Company  against any liability  associated  with Kern River for
this claim;  however, no assurance can be given as to the ability of Williams to
perform on this indemnity  should it become  necessary.  Williams,  on behalf of
Kern River and other entities, anticipates joining with Northern Natural Gas and
other defendants in contesting  certification of the plaintiff class. Kern River
and Northern  Natural Gas believe that this claim is without merit and that Kern
River's  and  Northern  Natural  Gas' gas  measurement  techniques  have been in
accordance with industry standards and its tariff.

Kern River's 2003 Expansion Project
-----------------------------------

The 2003  Expansion  Project is a new parallel  717-mile loop pipeline that will
begin in Lincoln County, Wyoming and terminate in Kern County,  California.  The
2003 Expansion  Project began  construction on August 6, 2002 and is expected to
be completed  and  operational  by May 1, 2003 at a total cost of  approximately
$1.2 billion.  The 2003 Expansion  Project is being financed with  approximately
70%  debt  and  30%  equity,  consistent  with  Kern  River's  original  capital
structure,  the  application  for the  FERC  approval  described  above  and the
limitations  contained in the indenture for Kern River's existing secured senior
notes.

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

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

                                      -90-

<PAGE>

Philippines
-----------

Casecnan Construction Arbitration

On February 12, 2001, the contractor  filed a Request for  Arbitration  with the
International  Chamber of  Commerce  seeking  schedule  relief of up to 153 days
through August 31, 2001 resulting from various alleged force majeure events.  In
its March 20,  2001  Supplement  to  Request  for  Arbitration,  the  contractor
requested  compensation for alleged additional costs of approximately $4 million
it incurred from the claimed force majeure  events to the extent it is unable to
recover from its  insurer.  On April 20, 2001,  the  contractor  filed a further
supplement  seeking an additional  compensation for damages of approximately $62
million for the alleged force majeure event (and geologic conditions) related to
the  collapse of the surge  shaft.  The  contractor  also has  alleged  that the
circumstances  in which CE Casecnan  assumed control of the Casecnan Project and
placed  it  into  commercial  operation  on  December  11,  2001  amounted  to a
repudiation of the  construction  contract and has filed a claim for unspecified
quantum  meruit  damages,  and has  further  alleged  that the delay  liquidated
damages  clause which  provides for payments of $125,000 per day for each day of
delay in completion of the Project for which the  contractor is  responsible  is
unenforceable.  The arbitration is being conducted  applying New York law and in
accordance with the rules of the International Chamber of Commerce.

Hearings  have  been held in  connection  with this  arbitration  in July  2001,
September  2001,  January 2002,  March 2002,  November 2002 and January 2003. As
part of those hearings,  on June 25, 2001, the arbitration  tribunal temporarily
enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di
Roma in  support  of the  contractor's  obligations  to CE  Casecnan  for  delay
liquidated damages. As a result of the continuing nature of that injunction,  on
April 26, 2002, CE Casecnan and the contractor  mutually  agreed that no demands
would  be made on the  Banca  di Roma  demand  guaranty  except  pursuant  to an
arbitration  award. As of December 31, 2002,  however,  CE Casecnan has received
approximately $6.0 million of liquidated damages from demands made on the demand
guarantees  posted  by  a  separate  financial  institution  on  behalf  of  the
contractor.  On November 7, 2002, the  International  Chamber of Commerce issued
the arbitration  tribunal's partial award with respect to the contractor's force
majeure and  geologic  conditions  claims.  The  arbitration  panel  awarded the
contractor  18 days of  schedule  relief in the  aggregate  for all of the force
majeure events and awarded the contractor  $3.8 million with respect to the cost
of the collapsed surge shaft.  The $3.8 million is shown as part of the accounts
payable and accrued expenses balance at the end of December 31, 2002. All of the
contractor's other claims with respect to force majeure and geologic  conditions
were denied.

Further hearings on the contractor's  repudiation and quantum meruit claims, the
alleged  unenforceability  of the delay  liquidated  damages  clause and certain
other matters had been  scheduled for March 24 through March 28, 2003,  but were
postponed  as a result of the  commencement  of  military  action  in Iraq.  The
arbitral  tribunal has requested  the parties to indicate the earliest  possible
date on which they are available and will then reschedule the hearings.

If the contractor were to prevail on its claim that the delay liquidated damages
clause is unenforceable, CE Casecnan would not be entitled to collect such delay
damages for the period from March 31, 2001 through  December  11,  2001.  If the
contractor  were to prevail in its  repudiation  claim and prove quantum  meruit
damages in excess of amounts already paid to the  contractor,  CE Casecnan could
be liable to make additional  payments to the contractor.  CE Casecnan  believes
all such  allegations and claims are without merit and is vigorously  contesting
the contractor's claims.

Casecnan NIA Arbitration

Under  the  terms  of the  Project  Agreement,  NIA has  the  option  of  timely
reimbursing CE Casecnan  directly for certain taxes CE Casecnan has paid. If NIA
does not so reimburse CE  Casecnan,  the taxes paid by CE Casecnan  result in an
increase in the Water  Delivery  Fee.  The payment of certain  other taxes by CE
Casecnan  results  automatically in an increase in the Water Delivery Fee. As of
December 31, 2002,  CE Casecnan has paid  approximately  $56.7  million in taxes
which as a result of the foregoing provisions has resulted in an increase in the
Water  Delivery Fee. NIA has failed to pay the portion of the Water Delivery Fee
each month  which  relates to the payment of these  taxes by CE  Casecnan.  As a
result of this non-payment,  on August 19, 2002, CE Casecnan filed a Request for
Arbitration  against NIA,  seeking payment of such portion of the Water Delivery
Fee and  enforcement of the relevant  provision of the Project  Agreement  going
forward.  The arbitration  will be conducted in accordance with the rules of the
International  Chamber of  Commerce.  NIA is expected to file its answer late in
the first  quarter  or early in the  second  quarter,  2003.  The  three  member
arbitration  panel has been confirmed by the  International  Chamber of Commerce
and an initial organizational hearing is scheduled for the second quarter, 2003.

                                      -91-

<PAGE>

Casecnan Stockholder Litigation

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

In February  2003, San Lorenzo Ruiz Builders and  Developers  Group,  Inc. ("San
Lorenzo"),  an  original  shareholder  substantially  all of whose  shares in CE
Casecnan a subsidiary of the Company  purchased in 1998,  threatened to initiate
legal action in the Philippines in connection with certain aspects of its option
to repurchase such shares on or prior to commercial operation of the Project. CE
Casecnan  believes  that San  Lorenzo  has no valid  basis for any claim and, if
named as a defendant in any action that may be  commenced  by San Lorenzo,  will
vigorously defend any such action.

                                      -92-
<PAGE>


21. SEGMENT INFORMATION:

With its 2002  acquisitions of Kern River and Northern  Natural Gas, the Company
has  identified  seven  reportable   operating  segments  principally  based  on
management  structure:  MidAmerican Energy, Kern River, Northern Natural Gas, CE
Electric UK, CalEnergy  Generation-Domestic,  CalEnergy Generation-Foreign,  and
HomeServices. Information related to the Company's reportable operating segments
is shown below (in thousands).
<TABLE>
<CAPTION>

                                                                                                  MEHC
                                                                                              (PREDECESSOR)
                                             YEAR ENDED DECEMBER 31,      MARCH 14, 2000     JANUARY 1, 2000
                                          ----------------------------       THROUGH            THROUGH
                                             2002             2001       DECEMBER 31, 2000   MARCH 13, 2000
                                          -----------      -----------   -----------------   --------------

<S>                                       <C>              <C>              <C>              <C>
OPERATING REVENUE:
MidAmerican Energy ..................     $ 2,240,879      $ 2,388,650      $ 1,860,499      $  455,844
Kern River ..........................         127,254             --               --              --
Northern Natural Gas ................         176,880             --               --              --
CE Electric UK ......................         795,366        1,443,997        1,499,768         498,142
CalEnergy Generation-Domestic .......          38,546           37,299            2,757             438
CalEnergy Generation-Foreign ........         326,316          203,482          146,798          40,124
HomeServices ........................       1,138,332          641,934          408,492          60,603
                                          -----------      -----------      -----------      ----------
Segment operating revenue ...........       4,843,573        4,715,362        3,918,314       1,055,151
Corporate/other .....................         (49,563)         (18,581)            (214)          1,214
                                          -----------      -----------      -----------      ----------
Total operating revenue .............     $ 4,794,010      $ 4,696,781      $ 3,918,100      $1,056,365
                                          ===========      ===========      ===========      ==========

DEPRECIATION AND AMORTIZATION:
MidAmerican Energy ..................     $   269,412      $   286,590      $   184,955      $   45,184
Kern River ..........................          17,165             --               --              --
Northern Natural Gas ................          18,151             --               --              --
CE Electric UK ......................         116,792          133,865          108,637          31,964
CalEnergy Generation-Domestic .......           8,714            5,439            2,183             250
CalEnergy Generation-Foreign ........          88,036           66,315           52,685          13,514
HomeServices ........................          22,072           17,201            8,695           2,891
                                          -----------      -----------      -----------      ----------
Segment depreciation and amortization         540,342          509,410          357,155          93,803
Corporate/other .....................         (14,440)          29,292           26,196           3,475
                                          -----------      -----------      -----------      ----------
Total depreciation and amortization .     $   525,902      $   538,702      $   383,351      $   97,278
                                          ===========      ===========      ===========      ==========

INTEREST EXPENSE, NET:
MidAmerican Energy ..................     $   119,225      $   113,980      $    94,425      $   24,579
Kern River ..........................          33,036             --               --              --
Northern Natural Gas ................          22,987             --               --              --
CE Electric UK ......................         183,472          112,308           74,335          21,189
CalEnergy Generation-Domestic .......          20,913           10,835            1,829             793
CalEnergy Generation-Foreign ........          68,338           30,875           34,458           9,713
HomeServices ........................           4,256            3,884            2,328             785
                                          -----------      -----------      -----------      ----------
Segment interest expense, net .......         452,227          271,882          207,375          57,059
Corporate/other .....................         157,683          140,912          104,029          28,755
                                          -----------      -----------      -----------      ----------
Total interest expense, net .........     $   609,910      $   412,794      $   311,404      $   85,814
                                          ===========      ===========      ===========      ==========
</TABLE>

                                      -93-
<PAGE>
<TABLE>
<CAPTION>
                                                                                                            MEHC
                                                        YEAR ENDED DECEMBER 31,                         (PREDECESSOR)
                                                       --------------------------   MARCH 14, 2000     JANUARY 1, 2000
                                                                                        THROUGH           THROUGH
                                                          2002             2001     DECEMBER 31, 2000  MARCH 13, 2000
                                                       -----------      ---------   -----------------  --------------

<S>                                                    <C>              <C>            <C>                <C>
INCOME BEFORE PROVISIONS FOR INCOME TAXES:
  MidAmerican Energy .............................     $   241,005      $ 211,300      $ 181,797          $  63,315
  Kern River .....................................          60,700           --             --                 --
  Northern Natural Gas ...........................          42,882           --             --                 --
  CE Electric UK .................................         266,755        173,816         83,108             58,673
  CalEnergy Generation-Domestic ..................          (4,963)        46,765         30,697              2,877
  CalEnergy Generation-Foreign ...................         149,915         94,542         49,787             15,976
  HomeServices ...................................          69,979         42,945         31,015             (4,929)
                                                       -----------      ---------      ---------          ---------
  Segment income before provision for income taxes         826,273        569,368        376,404            135,912
  Corporate/other ................................        (183,175)       (65,484)      (157,200)           (44,742)
                                                       -----------      ---------      ---------          ---------
    Total income before provision for income taxes     $   643,098      $ 503,884      $ 219,204          $  91,170
                                                       ===========      =========      =========          =========

PROVISION FOR INCOME TAXES:
  MidAmerican Energy .............................     $    99,782      $  95,688      $  77,450          $  27,943
  Kern River .....................................          23,014           --             --                 --
  Northern Natural Gas ...........................          16,947           --             --                 --
  CE Electric UK .................................          25,245        163,253         30,065             18,761
  CalEnergy Generation-Domestic ..................         (15,203)         2,706         (1,929)                (8)
  CalEnergy Generation-Foreign ...................          37,577         29,712         29,194                373
  HomeServices ...................................          28,207         15,953         12,300             (1,992)
                                                       -----------      ---------      ---------          ---------
  Segment provision for income taxes .............         215,569        307,312        147,080             45,077
  Corporate/other ................................        (115,981)       (57,248)       (93,803)           (14,069)
                                                       -----------      ---------      ---------          ---------
    Total provision for income taxes .............     $    99,588      $ 250,064      $  53,277          $  31,008
                                                       ===========      =========      =========          =========

CAPITAL EXPENDITURES:
  MidAmerican Energy .............................     $   358,194      $ 252,615      $ 194,045          $  23,977
  Kern River .....................................         769,464           --             --                 --
  Northern Natural Gas ...........................          62,409           --             --                 --
  CE Electric UK .................................         222,622        176,464         95,806             22,210
  CalEnergy Generation-Domestic ..................          61,920         52,940        151,289             53,011
  CalEnergy Generation-Foreign ...................           7,830         83,954         87,781             22,263
  HomeServices ...................................          18,273          9,878          6,996              2,052
                                                       -----------      ---------      ---------          ---------
  Segment capital expenditures ...................       1,500,712        575,851        535,917            123,513
  Corporate/other ................................           7,373            901          2,812                 28
                                                       -----------      ---------      ---------          ---------
    Total capital expenditures ...................     $ 1,508,085      $ 576,752      $ 538,729          $ 123,541
                                                       ===========      =========      =========          =========
</TABLE>

                                      -94-
<PAGE>
                                              AS OF DECEMBER 31,
                                           --------------------------
                                              2002           2001
                                           -----------    -----------
          Identifiable assets:
          MidAmerican Energy ..........    $ 6,034,742    $ 5,848,035
          Kern River ..................      1,797,850           --
          Northern Natural Gas ........      2,162,367           --
          CE Electric UK ..............      4,717,524      4,340,147
          CalEnergy Generation-Domestic        909,832        870,664
          CalEnergy Generation-Foreign         974,852        950,035
          HomeServices ................        488,270        322,552
                                           -----------    -----------
          Segment identifiable assets .     17,085,437     12,331,433
          Corporate/other .............        931,018        295,219
                                           -----------    -----------
          Total identifiable assets ...    $18,016,455    $12,626,652
                                           ===========    ===========

          LONG-LIVED ASSETS:
          MidAmerican Energy ..........    $ 4,999,637    $ 4,879,884
          Kern River ..................      1,594,225           --
          Northern Natural Gas ........      1,818,469           --
          CE Electric UK ..............      3,936,598      3,650,385
          CalEnergy Generation-Domestic        594,282        571,404
          CalEnergy Generation-Foreign         724,908        805,050
          HomeServices ................        384,899        262,175
                                           -----------    -----------
          Segment long-lived assets ...     14,053,018     10,168,898
          Corporate/other .............         15,201          7,019
                                           -----------    -----------
          Total long-lived assets .....    $14,068,219    $10,175,917
                                           ===========    ===========


The remaining  differences from the segment amounts to the consolidated  amounts
described as  "Corporate/Other"  relate  principally to the corporate  functions
including  administrative  costs,  corporate cash and related  interest  income,
intersegment eliminations, and fair value adjustments relating to acquisitions.

Excess of cost over fair value as of  December  31,  2001 and  changes  from the
period from January 1, 2002 through December 31, 2002 by segment is as follows:

<TABLE>
<CAPTION>
                                     MIDAMERICAN      KERN     NORTHERN     CE ELECTRIC    GENERATION      HOME-
                                        ENERGY        RIVER   NATURAL GAS        UK         DOMESTIC      SERVICES      TOTAL
                                     -----------     -------  -----------   -----------    ----------     ---------   -----------
<S>                                  <C>             <C>        <C>         <C>             <C>           <C>         <C>
Goodwill at December 31, 2001 ...    $ 2,160,004     $  --      $   --      $ 1,104,262     $ 142,726     $ 231,554   $ 3,638,546
Acquisitions/purchase
price accounting adjustments ....           --        32,547     414,721         56,626          --         108,914       612,808
Goodwill written off related to
sale of business unit ...........           --          --          --          (49,587)         --            --         (49,587)
Translation adjustment ..........           --          --          --           86,296          --            --          86,296
Other adjustments
Deferred tax adjustments ........         (8,946)       --          --           (1,675)      (15,962)         (477)      (27,060)
Stock option adjustments ........         (1,776)       --          --             (601)         (324)         (170)       (2,871)
                                     -----------     -------    --------    -----------     ---------     ---------   -----------
Goodwill at December 31, 2002 ...    $ 2,149,282     $32,547    $414,721    $ 1,195,321     $ 126,440     $ 339,821   $ 4,258,132
                                     ===========     =======    ========    ===========     =========     =========   ===========
</TABLE>
                                      -95-
<PAGE>

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE.

        Not applicable.

                                      -96-
<PAGE>

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

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

Name                       Position
----                       --------

David L. Sokol             Chairman of the Board, Chief Executive Officer
                             and Director
Gregory E. Abel            President, Chief Operating Officer and Director
Patrick J. Goodman         Senior Vice President and Chief Financial Officer
Douglas L. Anderson        Senior Vice President, General Counsel and
                             Corporate Secretary
Keith D. Hartje            Senior Vice President and Chief Administrative
                             Officer
Warren E. Buffett          Director
Walter Scott Jr.           Director
Marc D. Hamburg            Director
W. David Scott             Director
Edgar D. Aronson           Director
John K. Boyer              Director
Stanley J. Bright          Director
Richard R. Jaros           Director

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

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

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

GREGORY E. ABEL, 40, President,  Chief Operating Officer and Director.  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,  36, 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.

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

KEITH D. HARTJE, 53, Senior Vice President and Chief Administrative Officer. Mr.
Hartje has been with  MidAmerican  Energy and its  predecessor  companies  since
1973. In that time, he has held a number of positions, including General Counsel
and Corporate Secretary,  District Vice President for southwest Iowa operations,
and Vice President, Corporate Communications.

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

                                      -97-
<PAGE>

WALTER SCOTT,  JR., 72,  Director.  Mr. Scott has been a director of the Company
since June 1991. Mr. Scott was the Chairman and Chief  Executive  Officer of the
Company from  January 8, 1992 until April 19, 1993.  For more than the past five
years, he has been Chairman of the Board of Directors of Level 3 Communications,
Inc., a successor to certain businesses of Peter Kiewit & Sons Inc. Mr. Scott is
a director of Peter  Kiewit & Sons Inc.,  Berkshire  Hathaway  Inc.,  Burlington
Resources, Inc., ConAgra, Inc., Valmont Industries,  Inc., Kiewit Materials Co.,
Commonwealth Telephone Enterprises, Inc. and RCN Corporation.

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

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

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

JOHN K. BOYER, 59, Director.  Mr. Boyer has been a director of the Company since
March 2000. He is a partner with Fraser, Stryker,  Meusey, Olson, Boyer & Bloch,
P.C.  from 1973 to present  with  emphasis on  corporate,  commercial,  federal,
state, and local taxation.

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

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

                                      -98-

<PAGE>


ITEM 11. EXECUTIVE COMPENSATION.

The following table sets forth the  compensation of its Chief Executive  Officer
and its four other most highly compensated  executive officers who were employed
as of December  31,  2002,  which the Company  refers to as its Named  Executive
Officers. Information is provided regarding its Named Executive Officers for the
last three  fiscal  years  during  which they were its  executive  officers,  if
applicable.
<TABLE>
<CAPTION>

                                                                                   RESTRICTED  SECURITITIES
     NAME AND PRINCIPAL        YEAR ENDED                           OTHER ANNUAL     STOCK      UNDERLYING     LTIP     ALL OTHER
         POSITIONS              DEC. 31     SALARY(1)   BONUS (1)       COMP         AWARDS      OPTIONS      PAYOUTS     COMP(2)
----------------------------   ----------   ---------   ----------  ------------   ----------  ------------   -------   ---------
<S>                                <C>     <C>         <C>          <C>              <C>         <C>           <C>       <C>
David L. Sokol ................    2002    $800,000    $2,750,000   $27,122,550(3)   $  --       $     --      $  --     $ 7,960
Chairman and ..................    2001     750,000     2,400,000            --         --             --         --      33,033
Chief Executive Officer .......    2000     750,000     4,250,000            --         --        2,199,277       --      40,430

Gregory E. Abel ...............    2002     540,000     2,200,000            --         --             --         --       7,636
President and .................    2001     520,000     1,150,000            --         --             --         --      23,657
Chief Operating Officer .......    2000     500,000     1,100,000            --         --          649,052       --      27,530

Patrick J. Goodman ............    2002     248,000       365,000       209,560(4)      --             --         --       7,353
Senior Vice President and .....    2001     240,000       260,000            --         --             --         --      13,527
Chief Financial Officer .......    2000     230,000     1,183,071            --         --             --         --      14,891

Douglas L. Anderson ...........    2002     200,000       325,000            --         --             --         --       7,150
Senior Vice President and .....    2001     154,427       200,000            --         --             --         --       6,630
General Counsel ...............    2000     120,000       591,806            --         --             --         --       6,630

Keith D. Hartje ...............    2002     180,000        65,000            --         --             --         --       7,796
Senior Vice President and .....    2001     180,000        60,000            --         --             --         --       6,630
Chief Administrative Officer ..    2000     178,173       138,647            --         --             --         --       6,630
</TABLE>

     (1)  Includes amounts voluntarily deferred by the executive, if applicable.

     (2)  Consists  of  401(k)  Plan  contributions  for 2002  for Mr.  Sokol of
          $7,150,  Mr. Abel of $7,150,  Mr. Goodman of $7,150,  Mr.  Anderson of
          $7,150 and Mr. Hartje of $7,796.  To offset its obligations  under the
          Company's  Executive Split Dollar Plan for executives whose retirement
          benefit cannot be fully funded  through the Company's Base  Retirement
          Plan  for  Salaried  Employees,  the  Company  has  agreed  to pay the
          premiums for  policies of split dollar life  insurance on the lives of
          such  executives.  No premiums  were paid in 2002 for Mr.  Sokol,  Mr.
          Abel,  or Mr.  Goodman.  Included  are the  insurance  premiums in the
          following  amounts  paid by the Company  with respect to the term life
          insurance  portion of premiums paid in 2002 for Mr. Sokol of $810, for
          Mr. Abel of $486 and for Mr. Goodman of $203.

     (3)  Cash  amount  paid to Mr.  Sokol  in  connection  with  the  Company's
          purchase of options to purchase the Company's common stock held by Mr.
          Sokol.  The amount paid is equal to the difference  between the option
          exercise prices and the agreed upon value per share.

     (4)  Includes  the cash amount  paid to Mr.  Goodman in  connection  with a
          subsidiary's  purchase of options to purchase the subsidiary's  common
          stock held by Mr. Goodman.  The amount paid is equal to the difference
          between  the option  exercise  prices  and the  agreed  upon value per
          share.

OPTION GRANTS IN LAST FISCAL YEAR

The Company did not grant any options during 2002.


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

The following table sets forth the option exercises and the number of securities
underlying  exercisable  and  unexercisable  options  held by each of its  Named
Executive Officers at December 31, 2002.

                                      -99-
<PAGE>

<TABLE>
<CAPTION>
                                                  UNDERLYING UNEXERCISED          VALUE OF UNEXERCISED
                     SHARES ACQUIRED   VALUE         OPTIONS HELD (#)            IN-THE-MONEY OPTIONS ($) (1)
                                                   ---------------------------   ----------------------------
          NAME       ON EXERCISE(#)   REALIZED $   EXERCISEABLE  UNEXERCISEABLE  EXERCISEABLE   UNEXERCISEABLE
-------------------  ---------------  ----------   ------------  --------------  ------------   --------------
<S>                         <C>           <C>        <C>              <C>            <C>             <C>
David L. Sokol              -             -          1,353,504        45,773         N/A             N/A
Gregory E. Abel             -             -            636,214        12,838         N/A             N/A
Patrick J. Goodman          -             -                  -             -           -               -
Douglas L. Anderson         -             -                  -             -           -               -
Keith D. Hartje             -             -                  -             -           -               -
</TABLE>

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

LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>

                       NUMBER OF SHARES,   PERFORMANCE OR OTHER
                       UNITS OR OTHER      PERIOD UNTIL MATURATION                 TARGET ($)   MAXIMUM
     NAME                RIGHTS (#) (1)        OR PAYOUT            THRESHOLD($)      (2)        (#)
-------------------    -----------------   -----------------------  ------------   ----------   -------
<S>                           <C>             <C>                     <C>             <C>       <C>
Patrick J. Goodman            N/A             December 31,2006        372,000         N/A       372,000
Douglas L. Anderson           N/A             December 31,2006        300,000         N/A       300,000
Keith D. Hartje               N/A             December 31,2006        270,000         N/A       270,000
</TABLE>

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

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

COMPENSATION OF DIRECTORS

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

RETIREMENT PLANS

The Company  maintains a Supplemental  Retirement Plan for Designated  Officers,
which the Company  refers to as the  Supplemental  Plan,  to provide  additional
retirement  benefits to designated  participants,  as determined by the Board of
Directors.  Messrs.  Sokol,  Abel,  Goodman and Hartje are  participants  in the
Supplemental Plan. The Supplemental Plan provides annual retirement  benefits up
to  sixty-five  percent of a  participant's  Total Cash  Compensation  in effect
immediately  prior to  retirement,  subject to a $1 million  maximum  retirement
benefit.  "Total  Cash  Compensation"  means the  highest  amount  payable  to a
participant  as monthly base salary during the five years  immediately  prior to
retirement  multiplied  by 12 plus the average of the  participant's  last three
years awards under an annual incentive bonus program and special,  additional or
non-recurring  bonus  awards,  if any, that are required to be included in Total
Cash Compensation  pursuant to a participant's  employment agreement or approved
for  inclusion  by the  Board.  Participants  must be  credited  with five years
service in order to be eligible to receive benefits under the Supplemental Plan.
Each of the Company's  Named  Executive  Officers has or will have five years of
credited service with the Company as of their respective  normal  retirement age
and will be  eligible  to  receive  benefits  under  the  Supplemental  Plan.  A
participant  who

                                     -100-
<PAGE>

elects early  retirement is entitled to reduced  benefits under the Supplemental
Plan,  however,  in  accordance  with their  respective  employment  agreements,
Messrs. Sokol and Abel are eligible to receive the maximum retirement benefit at
age  47.  A  survivor  benefit  is  payable  to a  surviving  spouse  under  the
Supplemental  Plan.  Benefits  from the  Supplemental  Plan  will be paid out of
general corporate funds;  however,  through a rabbi trust, the Company maintains
life insurance on the  participants in amounts expected to be sufficient to fund
the  after-tax  cost  of  the  projected  benefits.   Deferred  compensation  is
considered part of the salary covered by the Supplemental Plan.

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

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

Part  A of  the  IOR  Supplemental  Plan  provides  retirement  benefits  up  to
sixty-five  percent of a  participant's  highest  annual  salary during the five
years prior to retirement  reduced by the participant's  MidAmerican  Retirement
Plan benefit.  The percentage applied is based on years of accredited service. A
participant  who elects early  retirement is entitled to reduced  benefits under
the plan.  A survivor  benefit is payable to a surviving  spouse.  Benefits  are
adjusted  annually for inflation.  Part B of the IOR Supplemental  Plan provides
that an additional one hundred-fifty  percent of annual salary is to be paid out
to participants  at the rate of ten percent per year over fifteen years,  except
in the event of a  participant's  death, in which event the unpaid balance would
be paid to the  participant's  beneficiary or estate.  Deferred  compensation is
considered part of the salary covered by the IOR Supplemental Plan.

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

                                    ESTIMATED ANNUAL BENEFIT
          TOTAL CASH       ------------------------------------------
         COMPENSATION                 AGE AT RETIREMENT
       AT RETIREMENT ($)       55              60              65
       -----------------   ----------      ----------      ----------
           $  400,000      $  220,000      $  240,000      $  260,000
              500,000         275,000         300,000         325,000
              600,000         330,000         360,000         390,000
              700,000         385,000         420,000         455,000
              800,000         440,000         480,000         520,000
              900,000         495,000         540,000         585,000
            1,000,000         550,000         600,000         650,000
            1,250,000         687,500         750,000         812,500
            1,500,000         825,000         900,000         975,000
            1,750,000         962,500       1,000,000       1,000,000
            2,000,000
           and greater      1,000,000       1,000,000       1,000,000

                                     -101-
<PAGE>
EMPLOYMENT AGREEMENTS

Pursuant to his  employment  agreement Mr. Sokol serves as Chairman of its Board
of Directors and Chief Executive Officer. The employment agreement provides that
Mr. Sokol is to receive an annual base salary of not less than $750,000,  senior
executive  employee benefits and annual bonus awards that shall not be less than
$675,000. Subject to an annual renewal provision, such agreement is scheduled to
expire on August 21, 2003.

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

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

Under the terms of separate  employment  agreements between the Company and each
of Messrs. Abel and Goodman,  each of such executives is entitled to receive two
years base salary  continuation,  payments in respect of average bonuses for the
prior two years and two years continued  option vesting in the event the Company
terminate his employment  other than for cause.  If such persons were terminated
without cause, Messrs. Sokol, Abel and Goodman would currently be entitled to be
paid approximately $10,125,000, $4,750,000 and $1,175,000, respectively, without
giving effect to any tax related provisions.

                                     -102-

<PAGE>


ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
         RELATED STOCKHOLDER MATTERS.

The  following  table  sets  forth  certain  information   regarding  beneficial
ownership of the shares of its common stock and certain information with respect
to the beneficial  ownership of each director,  its Named Executive Officers and
all directors and executive officers as a group as of December 31, 2002.

                                              NUMBER OF SHARES
                                                BENEFICIALLY    PERCENTAGE OF
     NAME AND ADDRESS OF BENEFICIAL OWNER (1)     OWNED(2)        CLASS (2)
    ----------------------------------------  ----------------  -------------
     Common Stock:
       Walter Scott, Jr. (3) ..............        5,000,000           53.87%
       David L. Sokol (4) .................        1,708,224           15.10%
       Berkshire Hathaway Inc. (5) ........          900,942            9.71%
       Gregory E. Abel (6) ................          700,713            6.20%
       W. David Scott (7) .................          624,350            6.73%
       Douglas L. Anderson ................                -               -
       Edgar D. Aronson ...................                -               -
       Stanley J. Bright ..................                -               -
       John K. Boyer ......................                -               -
       Warren E. Buffett (8) ..............                -               -
       Patrick J. Goodman .................                -               -
       Marc D. Hamburg (8) ................                -               -
       Richard R. Jaros ...................                -               -
       Keith D. Hartje ....................                -               -
       All directors and executive officers        8,934,229           78.99%
         as a group (14 persons)

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

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

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

(4)  Includes  options to  purchase  1,384,019  shares of common  stock that are
     exercisable within 60 days.

(5)  Such  beneficial  owner's  address is 1440 Kiewit  Plaza,  Omaha,  Nebraska
     68131.

(6)  Includes  options to  purchase  644,773  shares of common  stock  which are
     exercisable within 60 days.

(7)  Includes shares held by trusts for the benefit of or controlled by W. David
     Scott. Such beneficial  owner's address is 11422 Miracle Hills Drive, Suite
     400,  Omaha,  Nebraska 68154.

(8)  Excludes 900,942 shares of common stock held by Berkshire  Hathaway Inc. of
     which beneficial ownership of such shares is disclaimed.

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

Pursuant to a shareholders  agreement,  following March 14, 2003,  Walter Scott,
Jr. or any of the Scott  Family  Interests  would be able to  require  Berkshire
Hathaway to purchase,  for an agreed value or an appraised  value, any or all of
Walter Scott,  Jr.'s and the Scott Family Interests' shares of its common stock,
provided that Berkshire  Hathaway is then a purchaser of a type which is able to
consummate  such a purchase  without  causing it or any of its affiliates or the
Company  or any  of its  subsidiaries  to  become  subject  to  regulation  as a
registered holding company or a subsidiary of a

                                     -103-
<PAGE>


registered holding company under PUHCA. Berkshire Hathaway is not currently such
a purchaser.  The consummation of such a transaction could result in a change in
control with respect to the Company.

MEHC's Amended and Restated Articles of Incorporation provide that each share of
the Zero Coupon Convertible  Preferred Stock is convertible at the option of the
holder thereof into one conversion  unit, which is one share of its common stock
subject to certain adjustments as described in its articles, upon the occurrence
of a Conversion Event. A "Conversion  Event" includes (1) any conversion of Zero
Coupon Convertible Preferred Stock that would not cause the holder of the shares
of common stock issued upon  conversion (or any affiliate of such holder) or the
Company to become subject to regulation as a registered  holding company or as a
subsidiary of a registered holding company under PUHCA either as a result of the
repeal or amendment of PUHCA,  the number of shares  involved or the identity of
the holder of such shares and (2) a Company Sale. A "Company  Sale" includes its
involuntary or voluntary liquidation, dissolution, recapitalization,  winding-up
or termination and any merger, consolidation or sale of all or substantially all
of its assets. The conversion by Berkshire Hathaway of its shares of Zero Coupon
Convertible  Preferred  Stock into its common  stock could result in a change in
control  with  respect  to  beneficial  ownership  of its voting  securities  as
calculated pursuant to Rule 13d-3(d) under the Securities Exchange Act.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

Under a subscription  agreement with the Company,  Berkshire Hathaway has agreed
to  purchase,   under  certain   circumstances,   additional  11%  trust  issued
mandatorily  redeemable  preferred  securities in the event preferred securities
outstanding  prior to the closing of its acquisition by a private investor group
on March 14, 2000 are tendered for conversion to cash by the current holders.

The Company  provided a guarantee in favor of a third party lender in connection
with a $1,663,998.75 loan from such lender to its President, Gregory E. Abel, in
March of 2000. The loan matures on April 1, 2010. The proceeds of this loan were
used by Mr. Abel to purchase 47,475 shares of the Company's  common stock.  Such
common stock (together with 8,465 additional shares of common stock owned by Mr.
Abel) also secures the loan. The entire  original  principal  amount of the loan
and the guarantee remain presently outstanding.

In order to finance its $275 million preferred stock investment in Williams,  on
March 7, 2002, the Company sold to Berkshire  Hathaway shares of its zero coupon
convertible  preferred stock. In order to finance its acquisition of Kern River,
on  March  12,  2002,  the  Company  sold  to  Berkshire   Hathaway  and/or  its
consolidated  subsidiaries  shares  of  its  no  par,  zero  coupon  convertible
preferred stock for $127 million and $323 million of 11% mandatorily  redeemable
preferred  securities of its subsidiary  trust due March 12, 2012 with scheduled
principal  payments  beginning in 2005. In order to finance its  acquisition  of
Northern Natural Gas, on August 16, 2002, the Company sold to Berkshire Hathaway
and/or  its  consolidated   subsidiaries   $950.0  million  of  11%  mandatorily
redeemable preferred securities of its subsidiary trust due August 31, 2012 with
scheduled  principal payments  beginning in 2003. Messrs.  Warren E. Buffett and
Walter Scott,  Jr. are members of the Board of Directors of Berkshire  Hathaway.
Messrs.  Buffett  and  Marc D.  Hamburg  are  executive  officers  of  Berkshire
Hathaway. Each of Messrs. Buffett,  Hamburg and Walter Scott serves on its Board
of Directors and  participates  in  deliberations  regarding  executive  officer
compensation.

On March 6, 2002, the Company purchased options to purchase shares of its common
stock from Mr. David L. Sokol,  its Chairman and Chief  Executive  Officer.  The
options purchased had exercise prices ranging from $18.50 to $29.01. The Company
paid  Mr.  Sokol  an  aggregate  amount  of  $27,122,550,  which is equal to the
difference  between  his option  exercise  prices  and an agreed  upon per share
value.  Mr.  Sokol  serves  on  its  Board  of  Directors  and  participates  in
deliberations regarding executive officer compensation.

In July 2002,  the  Company  purchased  557,686  options to  purchase  shares of
HomeServices   common  stock  from   directors,   officers   and   employees  of
HomeServices. The options purchased had exercise prices ranging from $11.3125 to
$15.00.  The Company  paid an  aggregate  of  $4,268,392,  which is equal to the
difference  between  the option  exercise  prices  and an agreed  upon per share
value.

The  Company  has not  purchased  any  other  options  or  securities  from  its
stockholders, directors or executive officers since January 1, 2002.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

There is no compensation committee of the Board of Directors. All members of the
Board of Directors  participate in  deliberations  regarding  executive  officer
compensation.  Messrs.  Sokol and Abel are current  officers and employees.  Mr.

                                     -104-
<PAGE>

Walter Scott is a former  officer.  Mr. Jaros is a former  officer and employee.
See "Certain Relationships and Related Transactions."

ITEM 14. CONTROLS AND PROCEDURES.

a)   Evaluation of disclosure  controls and  procedures:  Based on the Company's
     evaluation  as of a date  within 90 days of the filing  date of this Annual
     Report  on  Form  10-K,  the  principal  executive  officer  and  principal
     financial officer have concluded that the Company's disclosure controls and
     procedures  (as  defined  in  Rules   13a-14(c)  and  15d-14(c)  under  the
     Securities Exchange Act of 1934 (the Exchange Act)) are effective to ensure
     that information required to be disclosed by the Company in reports that it
     files or submits under the Exchange Act are recorded, processed, summarized
     and reported  within the time periods  specified in Securities and Exchange
     Commission  rules and  forms.  It should  be noted  that the  design of any
     system of  controls  is based in part upon  certain  assumptions  about the
     likelihood of future events,  and there can be no assurance that any design
     will  succeed in  achieving  its stated  goals under all  potential  future
     conditions, regardless of how remote.

b)   Changes in  internal  controls.  There were no  significant  changes in the
     Company's  internal  controls or in other factors that could  significantly
     affect these  controls  subsequent to the date of their  evaluation.  There
     were no  significant  deficiencies  or material  weaknesses,  and therefore
     there were no corrective actions taken.

                                     -105-

<PAGE>

                                     PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

     (a)  Financial Statements and Schedules

          (i)  Financial Statements

               Financial Statements are included in Part II of this Form 10-K

          (ii) Financial Statement Schedules

               See  Schedule I on Page 107.

               See  Schedule II on Page 110.

     (b)  Reports on Form 8-K

     The  Company  filed the  following  Current  Reports on Form 8-K during the
     fourth quarter of 2002:

          o    The  Company  filed a Current  Report on Form 8-K on  October  2,
               2002.

          o    The  Company  filed a Current  Report on Form 8-K on  October  4,
               2002.

          o    The Company  filed a Current  Report on Form 8-K on November  13,
               2002.

          o    The Company  filed a Current  Report on Form 8-K on November  14,
               2002.

     (c)  Exhibits

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

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

     Not applicable.

                                     -106-
<PAGE>

MIDAMERICAN ENERGY HOLDINGS COMPANY                                SCHEDULE I
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
As of December 31, 2002 and 2001
(Amounts in thousands)
<TABLE>
<CAPTION>
                                                                    2002           2001
                                                                 -----------    -----------
                                     ASSETS
<S>                                                              <C>            <C>
Current assets -
  Cash and cash equivalents ..................................   $   320,629    $     2,524
Investments in and advances to subsidiaries and joint ventures     5,459,832      3,432,528
Equipment, net ...............................................        15,984         17,605
Excess of cost over fair value of net assets acquired ........     1,185,963      1,211,814
Deferred charges and other assets ............................       151,126        129,501
                                                                 -----------    -----------
TOTAL ASSETS .................................................   $ 7,133,534    $ 4,793,972
                                                                 ===========    ===========

                      LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Accounts payable and other accrued liabilities .............   $    94,389    $    68,445
  Current portion of long-term debt ..........................       215,000           --
  Short-term debt ............................................          --          153,500
                                                                 -----------    -----------
    Total current liabilities ................................       309,389        221,945
                                                                 -----------    -----------
Non-current liabilities ......................................        11,885          6,480
Notes payable - affiliate ....................................        94,795        197,153
Parent company debt ..........................................     2,324,457      1,834,498
                                                                 -----------    -----------
  Total liabilities ..........................................     2,740,526      2,260,076
                                                                 -----------    -----------

Deferred income ..............................................        35,313         37,578
Company-obligated mandatorily redeemable
  preferred securities of subsidiary trusts ..................     2,063,412        788,151

Stockholders' equity:
Zero coupon  convertible  preferred  stock -
  authorized 50,000 shares, no par value,
  41,263 and 34,563 shares issued and
  outstanding at December 31, 2002 and 2001 ..................          --             --
Common stock -authorized 60,000 shares, no par value; 9,281
  shares issued and outstanding at December 31, 2002 and 2001           --             --
Additional paid in capital ...................................     1,956,509      1,553,073
Retained earnings ............................................       584,009        223,926
Accumulated other comprehensive loss, net ....................      (246,235)       (68,832)
                                                                 -----------    -----------
Total stockholders' equity ...................................     2,294,283      1,708,167
                                                                 -----------    -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ...................   $ 7,133,534    $ 4,793,972
                                                                 ===========    ===========
</TABLE>

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

                                     -107-

<PAGE>

MIDAMERICAN ENERGY HOLDINGS COMPANY                                 SCHEDULE I
PARENT COMPANY ONLY (CONTINUED)
CONDENSED STATEMENTS OF OPERATIONS
For the three years ended December 31, 2002
(Amounts in thousands)
<TABLE>
<CAPTION>

                                                                    2002       2001         2000
                                                                  --------   ---------    --------
<S>                                                               <C>        <C>          <C>
Revenue:
Equity in undistributed earnings of subsidiary companies
and joint ventures ............................................   $460,631   $ 608,896    $390,194
Cash dividends and distributions from subsidiary
companies and joint ventures ..................................    351,847      87,625      96,342
Interest and other income .....................................     18,243       2,248      13,818
                                                                  --------   ---------    --------
Total revenue .................................................    830,721     698,769     500,354
                                                                  --------   ---------    --------

COSTS AND EXPENSES:
General and administration ....................................     29,368      41,078      45,089
Depreciation and amortization .................................        815      31,537      25,716
Interest, net of capitalized interest .........................    173,240     148,680     141,891
                                                                  --------   ---------    --------
Total costs and expenses ......................................    203,423     221,295     212,696
                                                                  --------   ---------    --------
INCOME BEFORE PROVISION FOR INCOME TAXES ......................    627,298     477,474     287,658
Provision for income taxes ....................................     99,588     250,064      84,285
                                                                  --------   ---------    --------
INCOME BEFORE MINORITY INTEREST ...............................    527,710     227,410     203,373
Minority interest .............................................    147,667      80,137      70,804
                                                                  --------   ---------    --------
INCOME BEFORE AND CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE ................................    380,043     147,273     132,569
Cumulative effect of change in accounting principle, net of tax       --        (4,604)       --
                                                                  --------   ---------    --------
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ...................   $380,043   $ 142,669    $132,569
                                                                  ========   =========    ========
</TABLE>

The notes to the consolidated MEHC financial  statements are an integral part of
                       this financial statement schedule.
                                     -108-
<PAGE>


MIDAMERICAN ENERGY HOLDINGS COMPANY                                  SCHEDULE I
PARENT COMPANY ONLY (CONTINUED)
CONDENSED STATEMENTS OF CASH FLOWS
For the three years ended December 31, 2002
(Amounts in thousands)
<TABLE>
<CAPTION>

                                                           2002           2001         2000
                                                        -----------    ---------    -----------

<S>                                                     <C>            <C>          <C>
CASH FLOWS FROM OPERATING ACTIVITIES ................   $  (188,300)   $(272,906)   $  (299,862)

CASH FLOWS FROM INVESTING ACTIVITIES:
Decrease (increase) in advances to and investments in
subsidiaries and joint ventures .....................    (1,692,742)     204,118        143,052
Acquisition of MEHC (Predecessor) ...................          --           --       (2,048,266)
Other, net ..........................................        10,307       (5,297)        28,458
                                                        -----------    ---------    -----------
Net cash flows from investing activities ............    (1,682,435)     198,821     (1,876,756)
                                                        -----------    ---------    -----------

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common and preferred stock        402,000         --        1,428,024
Proceeds from issuance of trust preferred securities      1,273,000         --          454,772
Proceeds from issuances of parent company debt ......       700,000         --             --
Repayments of parent company debt ...................          --            (32)          --
Net (repayment of) proceeds from revolver ...........      (153,500)      68,500         85,000
Other ...............................................       (32,660)         (82)       (23,893)
                                                        -----------    ---------    -----------
Net cash flows from financing activities ............     2,188,840       68,386      1,943,903
                                                        -----------    ---------    -----------

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS        318,105       (5,699)      (232,715)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR ......         2,524        8,223        240,938
                                                        -----------    ---------    -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR ............   $   320,629    $   2,524    $     8,223
                                                        ===========    =========    ===========
SUPPLEMENTAL DISCLOSURES:
Interest paid, net of interest capitalized ..........   $   164,267    $ 148,999    $   144,147
                                                        ===========    =========    ===========
Income taxes paid ...................................   $   101,225    $ 133,139    $    94,405
                                                        ===========    =========    ===========
</TABLE>

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

                                     -109-
<PAGE>
                                                                   SCHEDULE II

                       MIDAMERICAN ENERGY HOLDINGS COMPANY
                 CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
                   FOR THE THREE YEARS ENDED DECEMBER 31, 2002
                             (Amounts in thousands)
<TABLE>
<CAPTION>

         COLUMN A                               COLUMN B                 COLUMN C                COLUMN D     COLUMN E
         --------                               ----------   ---------------------------------   --------     ----------
                                                BALANCE AT               ADDITIONS
                                                             ---------------------------------                BALANCE AT
                                                BEGINNING     CHARGED     OTHER    ACQUISITION                   END
         Description                             OF YEAR     TO INCOME   ACCOUNTS  RESERVES (2)  DEDUCTIONS    OF YEAR
         -----------                            ---------    ---------   --------  ------------  ----------   ----------
Reserves Deducted From Assets
To Which They Apply:

<S>                                                <C>         <C>         <C>      <C>         <C>           <C>
Reserve for uncollectible accounts receivable:

Year ended 2002 ..............................     $ 7,319     $27,782     $--      $10,142     $ (5,501)     $39,742

Year ended 2001 ..............................     $32,685     $17,061     $--      $  --       $(42,427)     $ 7,319

Year ended 2000 ..............................     $18,666     $40,024     $--      $  --       $(26,005)     $32,685

Reserves Not Deducted From Assets (1):

Year ended 2002 ..............................     $13,631     $ 2,798     $247     $  --       $ (5,695)     $10,981

Year ended 2001 ..............................     $25,063     $ 5,046     $--      $  --       $(16,478)     $13,631

Year ended 2000 ..............................     $17,696     $10,832     $--      $  --       $ (3,465)     $25,063
</TABLE>

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


(1)  Reserves not deducted from assets include estimated  liabilities for losses
     retained by MEHC for workers  compensation,  public  liability and property
     damage claims

(2)  Acquisition  reserves  represent  the  reserves  recorded at Kern River and
     Northern Natural Gas at the date of acquisition.

                                     -110-
<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 Des
Moines, State of Iowa, on this 31st day of March 2003.


                                      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 31, 2003
-------------------
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and
Director


/s/  Gregory E. Abel*                                        March 31, 2003
---------------------
Gregory E. Abel
President, Chief Operating Officer and Director


/s/  Patrick J. Goodman*                                     March 31, 2003
------------------------
Patrick J. Goodman
Senior Vice President and
Chief Financial Officer


/s/  Edgar D. Aronson*                                       March 31, 2003
---------------------
Edgar D. Aronson
Director


/s/  Stanley J. Bright*                                      March 31, 2003
-----------------------
Stanley J. Bright
Director


/s/  Walter Scott, Jr.*                                      March 31, 2003
-----------------------
Walter Scott, Jr.
Director

                                     -111-

<PAGE>


/s/  Marc D. Hamburg*                                        March 31, 2003
--------------------
Marc D. Hamburg
Director


/s/  Warren E. Buffett*                                      March 31, 2003
----------------------
Warren E. Buffett
Director


/s/  John K. Boyer*                                          March 31, 2003
------------------
John K. Boyer
Director


/s/  W. David Scott*                                         March 31, 2003
-------------------
W. David Scott
Director


/s/  Richard R. Jaros*                                       March 31, 2003
---------------------
Richard R. Jaros
Director


*By:/s/  Douglas L. Anderson                                 March 31, 2003
----------------------------
         Douglas L. Anderson
         Attorney-in-Fact


                                     -112-
<PAGE>


                     SECTION 302 CERTIFICATION FOR FORM 10-K


CERTIFICATIONS
--------------


I, David L. Sokol, certify that:


1. I have  reviewed  this  annual  report  on Form  10-K of  MidAmerican  Energy
Holdings Company;


2.  Based on my  knowledge,  this  annual  report  does not  contain  any untrue
statement of a material fact or omit to state a material fact  necessary to make
the statements made, in light of the  circumstances  under which such statements
were made,  not  misleading  with  respect to the period  covered by this annual
report;


3.  Based  on my  knowledge,  the  financial  statements,  and  other  financial
information  included  in this annual  report,  fairly  present in all  material
respects the financial  condition,  results of operations  and cash flows of the
registrant as of, and for, the periods presented in this annual report;


4.  The  registrant's  other  certifying  officers  and  I are  responsible  for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and the Company has:


a) designed  such  disclosure  controls and  procedures  to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made  known to the  Company by others  within  those  entities,  particularly
during the period in which this annual report is being prepared;


b) evaluated  the  effectiveness  of the  registrant's  disclosure  controls and
procedures  as of a date  within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and


c) presented in this annual report its conclusions  about the  effectiveness  of
the  disclosure  controls  and  procedures  based  on its  evaluation  as of the
Evaluation Date;


5. The registrant's other certifying officers and I have disclosed, based on its
most recent evaluation,  to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):


a) all significant  deficiencies in the design or operation of internal controls
which  could  adversely  affect the  registrant's  ability  to record,  process,
summarize and report  financial data and have  identified  for the  registrant's
auditors any material weaknesses in internal controls; and

b) any  fraud,  whether  or not  material,  that  involves  management  or other
employees who have a significant role in the registrant's internal controls; and

6. The  registrant's  other  certifying  officers  and I have  indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of its most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date:  March 31, 2003


                             /s/ David L. Sokol
                             -----------------------
                                 David L. Sokol
                             Chief Executive Officer

                                     -113-

<PAGE>

                     SECTION 302 CERTIFICATION FOR FORM 10-K


CERTIFICATIONS
--------------


I, Patrick J. Goodman, certify that:


1. I have  reviewed  this  annual  report  on Form  10-K of  MidAmerican  Energy
Holdings Company;


2.  Based on my  knowledge,  this  annual  report  does not  contain  any untrue
statement of a material fact or omit to state a material fact  necessary to make
the statements made, in light of the  circumstances  under which such statements
were made,  not  misleading  with  respect to the period  covered by this annual
report;


3.  Based  on my  knowledge,  the  financial  statements,  and  other  financial
information  included  in this annual  report,  fairly  present in all  material
respects the financial  condition,  results of operations  and cash flows of the
registrant as of, and for, the periods presented in this annual report;


4.  The  registrant's  other  certifying  officers  and  I are  responsible  for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and the Company has:


a) designed  such  disclosure  controls and  procedures  to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made  known to the  Company by others  within  those  entities,  particularly
during the period in which this annual report is being prepared;


b) evaluated  the  effectiveness  of the  registrant's  disclosure  controls and
procedures  as of a date  within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and


c) presented in this annual report its conclusions  about the  effectiveness  of
the  disclosure  controls  and  procedures  based  on its  evaluation  as of the
Evaluation Date;


5. The registrant's other certifying officers and I have disclosed, based on its
most recent evaluation,  to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):


a) all significant  deficiencies in the design or operation of internal controls
which  could  adversely  affect the  registrant's  ability  to record,  process,
summarize and report  financial data and have  identified  for the  registrant's
auditors any material weaknesses in internal controls; and


b) any  fraud,  whether  or not  material,  that  involves  management  or other
employees who have a significant role in the registrant's internal controls; and


6. The  registrant's  other  certifying  officers  and I have  indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of its most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.


Date:  March 31, 2003

                            /s/ Patrick J. Goodman
                            -------------------------
                               Patrick J. Goodman
                            Senior Vice President and
                             Chief Financial Officer

                                     -114-
<PAGE>

                                  EXHIBIT INDEX

 EXHIBIT NO.       DESCRIPTION
 -----------       -----------

3.1       Amended  and  Restated   Articles  of  Incorporation  of  the  Company
          effective March 6, 2002  (incorporated  by reference to Exhibit 3.3 to
          the Company's  Annual Report on Form 10-K for the year ended  December
          31, 2001).

3.2       Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the
          Company's Annual Report on Form 10-K/A for the year ended December 31,
          1999).

4.1       Indenture, dated as of October 4, 2002, by and between the Company and
          The Bank of New York, relating to the 4.625% Senior Notes due 2007 and
          the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit
          4.1 of the  Company's  Registration  Statement  No.  333-101699  dated
          December 6, 2002).

4.2       First  Supplemental  Indenture,  dated as of October  4, 2002,  by and
          between the  Company and The Bank of New York,  relating to the 4.625%
          Senior   Notes  due  2007  and  the  5.875%   Senior  Notes  due  2012
          (incorporated   by   reference   to  Exhibit  4.2  of  the   Company's
          Registration Statement No. 333-101699 dated December 6, 2002).

4.3       Registration  Rights  Agreement,  dated as of October 1, 2002,  by and
          between the Company and Credit Suisse First Boston (as  Representative
          for the Initial Purchasers)  (incorporated by reference to Exhibit 4.3
          of the Company's  Registration Statement No. 333-101699 dated December
          6, 2002).

4.4       Indenture for the 6 1/4% Convertible  Junior  Subordinated  Debentures
          due 2012,  dated as of February  26,  1997,  between the  Company,  as
          issuer,  and  the  Bank  of New  York,  as  Trustee  (incorporated  by
          reference to Exhibit  10.129 to the  Company's  Annual  Report on Form
          10-K for the year ended December 31, 1995).

4.5       Indenture,  dated as of October  15,  1997,  among the Company and IBJ
          Schroder Bank & Trust Company,  as Trustee  (incorporated by reference
          to  Exhibit  4.1 to the  Company's  Current  Report  on Form 8-K dated
          October 23, 1997).

4.6       Form of First Supplemental Indenture for the 7.63% Senior Notes in the
          principal  amount of  $350,000,000  due 2007,  dated as of October 28,
          1997,  among the Company and IBJ  Schroder  Bank & Trust  Company,  as
          Trustee  (incorporated  by reference  to Exhibit 4.2 to the  Company's
          Current Report on Form 8-K dated October 23, 1997).

4.7       Form of Second  Supplemental  Indenture  for the 6.96% Senior Notes in
          the principal  amount of $215,000,000  due 2003, 7.23% Senior Notes in
          the principal  amount of $260,000,000  due 2005, 7.52% Senior Notes in
          the principal  amount of $450,000,000 due 2008, and 8.48% Senior Notes
          in  the  principal  amount  of  $475,000,000  due  2028,  dated  as of
          September  22, 1998 between the Company and IBJ Schroder  Bank & Trust
          Company,  as Trustee  (incorporated by reference to Exhibit 4.1 to the
          Company's Current Report on Form 8-K dated September 17, 1998.)

                                     -115-
<PAGE>


4.8       Form of Third Supplemental Indenture for the 7.52% Senior Notes in the
          principal  amount of $100,000,000  due 2008,  dated as of November 13,
          1998,  between the Company and IBJ Schroder Bank & Trust  Company,  as
          Trustee  (incorporated by reference to the Company's Current Report on
          Form 8-K dated November 10, 1998).

4.9       Indenture,  dated as of March 14, 2000, among the Company and the Bank
          of New York, as Trustee  (incorporated  by reference to Exhibit 4.9 to
          the Company's Annual Report on Form 10-K/A for the year ended December
          31, 1999).

4.10      Subscription  Agreement,  dated  as of March  14,  2000,  executed  by
          Berkshire Hathaway Inc.  (incorporated by reference to Exhibit 4.10 to
          the Company's Annual Report on Form 10-K/A for the year ended December
          31, 1999).

4.11      Indenture,  dated as of March 12,  2002,  between  the Company and the
          Bank of New York,  as Trustee  (incorporated  by  reference to Exhibit
          4.11 to the  Company's  Annual  Report on Form 10-K for the year ended
          December 31, 2001).

4.12      Subscription  Agreement,  dated  as of  March  7,  2002,  executed  by
          Berkshire Hathaway Inc.  (incorporated by reference to Exhibit 4.12 to
          the Company's  Annual Report on Form 10-K for the year ended  December
          31, 2001).

4.13      Subscription  Agreement,  dated  as of March  12,  2002,  executed  by
          Berkshire Hathaway Inc.  (incorporated by reference to Exhibit 4.13 to
          the Company's  Annual Report on Form 10-K for the year ended  December
          31, 2001).

4.14      Amended and Restated Declaration of Trust of MidAmerican Capital Trust
          III, dated as of August 16, 2002 (incorporated by reference to Exhibit
          4.14 of the  Company's  Registration  Statement No.  333-101699  dated
          December 6, 2002).

4.15      Amended and Restated Declaration of Trust of MidAmerican Capital Trust
          II, dated as of March 12, 2002  (incorporated  by reference to Exhibit
          4.15 of the  Company's  Registration  Statement No.  333-101699  dated
          December 6, 2002).

4.16      Amended and Restated Declaration of Trust of MidAmerican Capital Trust
          I, dated as of March 14, 2000  (incorporated  by  reference to Exhibit
          4.16 of the  Company's  Registration  Statement No.  333-101699  dated
          December 6, 2002).

4.17      Indenture,  dated as of August 16,  2002,  between the Company and the
          Bank of New York,  as Trustee  (incorporated  by  reference to Exhibit
          4.17 of the  Company's  Registration  Statement No.  333-101699  dated
          December 6, 2002).

4.18      Subscription  Agreement,  dated as of August  16,  2002,  executed  by
          Berkshire Hathaway Inc.  (incorporated by reference to Exhibit 4.18 of
          the Company's  Registration Statement No. 333-101699 dated December 6,
          2002).

4.19      Shareholders  Agreement,  dated as of March 14, 2000  (incorporated by
          reference to Exhibit 4.19 of the Company's  Registration Statement No.
          333-101699 dated December 6, 2002).

10.1      Employment Agreement between the Company and David L. Sokol, dated May
          10, 1999  (incorporated  by reference to Exhibit 10.1 to the Company's
          Annual Report on Form 10-K/A for the year ended December 31, 1999).

                                     -116-
<PAGE>

10.2      Amendment  No. 1 to the  Amended  and  Restated  Employment  Agreement
          between  the  Company  and  David  L.  Sokol,  dated  March  14,  2000
          (incorporated  by reference to Exhibit  10.2 to the  Company's  Annual
          Report on Form 10-K/A for the year ended December 31, 1999).

10.3      Non-Qualified  Stock Options Agreements of David L. Sokol, dated March
          14, 2000  (incorporated  by reference to Exhibit 10.3 of the Company's
          Registration Statement No. 333-101699 dated December 6, 2002).

10.4      Amended  and  Restated  Employment  Agreement  between the Company and
          Gregory E. Abel,  dated May 10, 1999  (incorporated  by  reference  to
          Exhibit  10.3 to the  Company's  Annual  Report on Form 10-K/A for the
          year ended December 31, 1999).

10.5      Non-Qualified Stock Options Agreements of Gregory E. Abel, dated March
          14, 2000  (incorporated  by reference to Exhibit 10.5 of the Company's
          Registration Statement No. 333-101699 dated December 6, 2002).

10.6      Employment Agreement between the Company and Patrick J. Goodman, dated
          April 21,  1999  (incorporated  by  reference  to Exhibit  10.5 to the
          Company's Annual Report on Form 10-K/A for the year ended December 31,
          1999).

10.7      MidAmerican  Energy Holdings  Company Long Term Incentive  Partnership
          Plan  (incorporated  by  reference  to Exhibit  10.7 of the  Company's
          Registration Statement No. 333-101699 dated December 6, 2002).

10.8      125 MW Power Plant-Upper  Mahiao  Agreement,  dated September 6, 1993,
          between PNOC-Energy Development Corporation and Ormat, Inc. as amended
          by the First  Amendment to 125 MW Power Plant Upper Mahiao  Agreement,
          dated as of January 28, 1994, the Letter  Agreement dated February 10,
          1994,  the Letter  Agreement  dated  February  18, 1994 and the Fourth
          Amendment to 125 MW Power Plant-Upper  Mahiao  Agreement,  dated as of
          March 7, 1994  (incorporated  by  reference  to  Exhibit  10.95 to the
          Company's  Annual Report on Form 10-K for the year ended  December 31,
          1993).

10.9      Credit Agreement,  dated April 8, 1994, among CE Cebu Geothermal Power
          Company, Inc., the Banks thereto, Credit Suisse as Agent (incorporated
          by reference to Exhibit 10.96 to the  Company's  Annual Report on Form
          10-K for the year ended December 31, 1993).

10.10     Credit  Agreement,  dated  as  of  April  8,  1994,  between  CE  Cebu
          Geothermal  Power  Company,  Inc.,  Export-Import  Bank of the  United
          States  (incorporated  by reference to Exhibit  10.97 to the Company's
          Annual Report on Form 10-K for the year ended December 31, 1993).

10.11     Pledge  Agreement,  dated as of April 8,  1994,  among CE  Philippines
          Ltd,  Ormat-Cebu  Ltd.,  Credit Suisse as Collateral Agent and CE Cebu
          Geothermal Power Company,  Inc.  (incorporated by reference to Exhibit
          10.98 to the  Company's  Annual Report on Form 10-K for the year ended
          December 31, 1993).

10.12     Overseas Private Investment  Corporation Contract of Insurance,  dated
          April 8, 1994, between the Overseas Private Investment Corporation and
          the  Company  through  its  subsidiaries  CE  International  Ltd.,  CE
          Philippines  Ltd., and Ormat-Cebu Ltd.  (incorporated  by reference to
          Exhibit 10.99 to the Company's Annual Report on Form 10-K for the year
          ended December 31, 1993).

                                      -117
<PAGE>

10.13     180 MW Power  Plant-Mahanagdong  Agreement,  dated September 18, 1993,
          between  PNOC-Energy  Development  Corporation and CE Philippines Ltd.
          and the  Company,  as amended by the First  Amendment  to  Mahanagdong
          Agreement,  dated June 22, 1994, the Letter  Agreement  dated July 12,
          1994,  the  Letter  Agreement  dated  July 29,  1994,  and the  Fourth
          Amendment to Mahanagdong Agreement,  dated March 3, 1995 (incorporated
          by reference to Exhibit 10.100 to the Company's  Annual Report on Form
          10-K for the year ended December 31, 1993).

10.14     Credit  Agreement,   dated  as  of  June  30,  1994,  among  CE  Luzon
          Geothermal Power Company,  Inc., American Pacific Finance Company, the
          Lenders party thereto,  and Bank of America National Trust and Savings
          Association  as  Administrative  Agent  (incorporated  by reference to
          Exhibit  10.101 to the  Company's  Annual  Report on Form 10-K for the
          year ended December 31, 1993).

10.15     Credit  Agreement,  dated  as of  June  30,  1994,  between  CE  Luzon
          Geothermal Power Company,  Inc. and  Export-Import  Bank of the United
          States  (incorporated  by reference to Exhibit 10.102 to the Company's
          Annual Report on Form 10-K for the year ended December 31, 1993).

10.16     Finance  Agreement,  dated  as of June  30,  1994,  between  CE  Luzon
          Geothermal  Power  Company,   Inc.  and  Overseas  Private  Investment
          Corporation  (incorporated  by  reference  to  Exhibit  10.103  to the
          Company's  Annual Report on Form 10-K for the year ended  December 31,
          1993).

10.17     Pledge  Agreement,  dated as of June 30,  1994,  among CE  Mahanagdong
          Ltd.,  Kiewit Energy  International  (Bermuda)  Ltd.,  Bank of America
          National  Trust and Savings  Association  as  Collateral  Agent and CE
          Luzon  Geothermal  Power Company,  Inc.  (incorporated by reference to
          Exhibit  10.104 to the  Company's  Annual  Report on Form 10-K for the
          year ended December 31, 1993).

10.18     Overseas Private Investment  Corporation Contract of Insurance,  dated
          July 29, 1994, between Overseas Private Investment Corporation and the
          Company,  CE  International  Ltd.,  CE  Mahanagdong  Ltd. and American
          Pacific  Finance  Company and  Amendment  No. 1, dated  August 3, 1994
          (incorporated  by reference to Exhibit 10.105 to the Company's  Annual
          Report on Form 10-K for the year ended December 31, 1993).

10.19     231 MW Power  Plant-Malitbog  Agreement,  dated  September  10,  1993,
          between PNOC- Energy  Development  Corporation and Magma Power Company
          and the First and Second  Amendments  thereto,  dated December 8, 1993
          and March 10, 1994, respectively (incorporated by reference to Exhibit
          10.106 to the Company's  Annual Report on Form 10-K for the year ended
          December 31, 1993).

10.20     Credit  Agreement,  dated as of November 10, 1994, among Visayas Power
          Capital  Corporation,  the Banks parties thereto and Credit Suisse, as
          Bank  Agent  (incorporated  by  reference  to  Exhibit  10.107  to the
          Company's  Annual Report on Form 10-K for the year ended  December 31,
          1993).

10.21     Finance  Agreement,  dated as of November  10, 1994,  between  Visayas
          Geothermal Power Company and Overseas Private  Investment  Corporation
          (incorporated  by reference to Exhibit 10.108 to the Company's  Annual
          Report on Form 10-K for the year ended December 31, 1993).

                                     -118-
<PAGE>

10.22     Pledge and Security  Agreement,  dated as of November 10, 1994,  among
          Broad Street  Contract  Services,  Inc.,  Magma Power  Company,  Magma
          Netherlands  B.V. and Credit Suisse,  as Bank Agent  (incorporated  by
          reference to Exhibit  10.109 to the  Company's  Annual  Report on Form
          10-K for the year ended December 31, 1993).

10.23     Overseas Private Investment  Corporation Contract of Insurance,  dated
          December 21, 1994, between Overseas Private Investment Corporation and
          Magma Netherlands,  B.V.  (incorporated by reference to Exhibit 10.110
          to the  Company's  Annual  Report  on Form  10-K  for the  year  ended
          December 31, 1993).

10.24     Agreement as to Certain Common Representations,  Warranties, Covenants
          and Other Terms,  dated November 10, 1994,  between Visayas Geothermal
          Power Company,  Visayas Power Capital  Corporation,  Credit Suisse, as
          Bank Agent,  Overseas  Private  Investment  Corporation  and the Banks
          named  therein  (incorporated  by reference  to Exhibit  10.111 to the
          Company's  1994 Annual Report on Form 10-K for the year ended December
          31, 1993).

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

10.26     Amended and Restated Casecnan Project Agreement,  dated June 26, 1995,
          between the National  Irrigation  Administration and CE Casecnan Water
          and Energy Company Inc.  (incorporated by reference to Exhibit 10.1 to
          CE Casecnan Water and Energy Company, Inc.'s Registration Statement on
          Form S-4 dated January 25, 1996).

10.27     Term Loan and Revolving  Facility  Agreement,  dated as of October 28,
          1996,  among CE  Electric UK  Holdings,  CE Electric UK plc and Credit
          Suisse  (incorporated  by reference to Exhibit 10.130 to the Company's
          Annual Report on Form 10-K for the year ended December 31, 1995).

10.28     Indenture  and First  Supplemental  Indenture,  dated March 11,  1999,
          between MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company
          and the First  Supplement  thereto relating to the $700 million Senior
          Notes and Bonds  (incorporated  by reference to the  Company's  Annual
          Report on Form 10-K for the year ended December 31, 1998).

10.29     General Mortgage  Indenture and Deed of Trust,  dated as of January 1,
          1993,  between  Midwest Power Systems Inc. and Morgan  Guaranty  Trust
          Company of New York,  Trustee  (incorporated  by  reference to Exhibit
          4(b)-1 to the Midwest  Resources  Inc.  Annual Report on Form 10-K for
          the year ended December 31, 1992, Commission File No. 1-10654).

10.30     First  Supplemental  Indenture,  dated as of January 1, 1993,  between
          Midwest  Power Systems Inc. and Morgan  Guaranty  Trust Company of New
          York,  Trustee  (incorporated  by reference  to Exhibit  4(b)-2 to the
          Midwest  Resources Inc.  Annual Report on Form 10-K for the year ended
          December 31, 1992, Commission File No. 1-10654).

10.31     Second Supplemental  Indenture,  dated as of January 15, 1993, between
          Midwest  Power Systems Inc. and Morgan  Guaranty  Trust Company of New
          York,  Trustee  (incorporated  by reference  to Exhibit  4(b)-3 to the
          Midwest  Resources Inc.  Annual Report on Form 10-K for the year ended
          December 31, 1992, Commission File No. 1-10654).

                                     -119-
<PAGE>

10.32     Third  Supplemental  Indenture,  dated  as of  May  1,  1993,  between
          Midwest  Power Systems Inc. and Morgan  Guaranty  Trust Company of New
          York, Trustee (incorporated by reference to Exhibit 4.4 to the Midwest
          Resources Inc.  Annual Report on Form 10-K for the year ended December
          31, 1993, Commission File No. 1-10654).

10.33     Fourth  Supplemental  Indenture,  dated as of October 1, 1994, between
          Midwest Power Systems Inc. and Harris Trust and Savings Bank,  Trustee
          (incorporated  by  reference  to Exhibit 4.5 to the Midwest  Resources
          Inc.  Annual Report on Form 10-K for the year ended December 31, 1994,
          Commission File No. 1-10654).

10.34     Fifth  Supplemental  Indenture,  dated as of November 1, 1994, between
          Midwest Power Systems Inc. and Harris Trust and Savings Bank,  Trustee
          (incorporated  by  reference  to Exhibit 4.6 to the Midwest  Resources
          Inc.  Annual Report on Form 10-K for the year ended December 31, 1994,
          Commission File No. 1-10654).

10.35     Sixth  Supplemental  Indenture,  dated  as of  July 1,  1995,  between
          Midwest Power Systems Inc. and Harris Trust and Savings Bank,  Trustee
          (incorporated  by reference to Exhibit 4.15 to the MidAmerican  Energy
          Company  Annual  Report on Form 10-K for the year ended  December  31,
          1995, Commission File No. 1-11505).

10.36     Indenture  of  Mortgage  and Deed of Trust,  dated as of March 1, 1947
          (incorporated  by reference to Exhibit 7B filed by  Iowa-Illinois  Gas
          and Electric Company as part of Commission File No. 2-6922).

10.37     Sixth Supplemental  Indenture,  dated as of July 1, 1967 (incorporated
          by reference to Exhibit 2.08 filed by  Iowa-Illinois  Gas and Electric
          Company as part of Commission File No. 2-28806).

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

10.39     Resignation   and   Appointment   of  successor   Individual   Trustee
          (incorporated  by reference to Exhibit  4.B.30 filed by  Iowa-Illinois
          Gas and Electric Company as part of Commission File No. 33-39211).

10.40     Twenty-Eighth  Supplemental  Indenture,  dated  as  of  May  15,  1992
          (incorporated by reference to Exhibit 4.31.B to the  Iowa-Illinois Gas
          and Electric  Company  Current  Report on Form 8-K dated May 21, 1992,
          Commission File No. 1-3573).

10.41     Intentionally left blank.

10.42     Thirtieth  Supplemental  Indenture,   dated  as  of  October  1,  1993
          (incorporated by reference to Exhibit 4.34.A to the  Iowa-Illinois Gas
          and Electric  Company  Current  Report on Form 8-K,  dated  October 7,
          1993, Commission File No. 1-3573).

                                     -120-
<PAGE>


10.43     Thirty-First  Supplemental  Indenture,  dated  as  of  July  1,  1995,
          between  Iowa-Illinois  Gas and Electric  Company and Harris Trust and
          Savings Bank,  Trustee  (incorporated  by reference to Exhibit 4.16 to
          the MidAmerican Energy Company Annual Report on Form 10-K for the year
          ended dated December 31, 1995, Commission File No. 1-11505).

10.44     Power Sales  Contract,  dated  September 22, 1967,  between Iowa Power
          Inc. and Nebraska Public Power District  (incorporated by reference to
          Exhibit  4-C-2  filed  by Iowa  Power  Inc.  as  part of  Registration
          Statement No. 2-27681).

10.45     Amendments  Nos. 1 and 2 to Power Sales  Contract  between  Iowa Power
          Inc. and Nebraska  Public Power  District,  dated  September  22, 1967
          (incorporated  by reference to Exhibit 4-C-2a filed by Iowa Power Inc.
          as part of Registration Statement No. 2-35624).

10.46     Amendment  No. 3, dated August 31, 1970,  to the Power Sales  Contract
          between  Iowa Power Inc. and Nebraska  Public  Power  District,  dated
          September 22, 1967 (incorporated by reference to Exhibit 5-C-2-b filed
          by Iowa Power Inc. as part of Registration Statement No. 2-42191).

10.47     Amendment  No. 4, dated March 28,  1974,  to the Power Sales  Contract
          between  Iowa Power Inc. and Nebraska  Public  Power  District,  dated
          September 22, 1967 (incorporated by reference to Exhibit 5-C-2-c filed
          by Iowa Power Inc. as part of Registration Statement No. 2-51540).

10.48     Amendment No. 5, dated  September 2, 1997, to the Power Sales Contract
          between MidAmerican Energy Company and Nebraska Public Power District,
          dated September 22, 1967 (incorporated by reference to Exhibit 10.2 to
          the former  MidAmerican Energy Holdings Company and MidAmerican Energy
          Company respective Quarterly Reports on the combined Form 10-Q for the
          quarter ended September 30, 1997,  Commission File Nos.  333-90553 and
          1-11505, respectively).

10.49     Amendment  No. 6, dated July 31,  2002,  to the Power  Sales  Contract
          between MidAmerican Energy Company and Nebraska Public Power District,
          dated September 22, 1967 (incorporated by reference to Exhibit 10.1 to
          the MidAmerican Funding, LLC and MidAmerican Energy Company respective
          Quarterly Reports on the combined Form 10-Q for the quarter ended June
          20, 2002, Commission File Nos. 1-12459 and 1-11505, respectively).

10.50     CalEnergy  Company,   Inc.   Voluntary  Deferred   Compensation  Plan,
          effective  December 1, 1997, First  Amendment,  dated as of August 17,
          1999,  and Second  Amendment  effective  March 2000  (incorporated  by
          reference to Exhibit 10.50 of the Company's Registration Statement No.
          333-101699 dated December 6, 2002).

10.51     MidAmerican  Energy  Holdings  Company  Executive  Voluntary  Deferred
          Compensation  Plan  (incorporated by reference to Exhibit 10.51 of the
          Company's  Registration  Statement No.  333-101699  dated  December 6,
          2002).

10.52     MidAmerican  Energy  Company First  Amended and Restated  Supplemental
          Retirement  Plan for  Designated  Officers  dated  as of May 10,  1999
          (incorporated   by  reference  to  Exhibit   10.52  of  the  Company's
          Registration Statement No. 333-101699 dated December 6, 2002).

                                     -121-
<PAGE>


10.53     MidAmerican Energy Company Restated  Executive  Deferred  Compensation
          Plan  (incorporated  by  reference  to Exhibit  10.6 to the  Company's
          Annual Report on Form 10-K/A for the year ended December 31, 1999).

10.54     MidAmerican  Energy Holdings  Company Restated  Deferred  Compensation
          Plan-Board  of Directors  (incorporated  by reference to Exhibit 10 to
          the Company's Quarterly Report on Form 10-Q for the quarter ended June
          30, 1999).

10.55     MidAmerican Energy Company Combined Midwest  Resources/Iowa  Resources
          Restated Deferred Compensation  Plan-Board of Directors  (incorporated
          by reference to Exhibit 10.63 to the  Company's  Annual Report on Form
          10-K/A for the year ended December 31, 1999).

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

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

10.58     Iowa-Illinois  Gas and Electric Company  Supplemental  Retirement Plan
          for Designated Officers,  as amended as of July 28, 1994 (incorporated
          by reference to the  Iowa-Illinois  Gas and  Electric  Company  Annual
          Report on Form 10-K for the year ended  December 31, 1994,  Commission
          File No. 1-3573).

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

10.60     Iowa-Illinois Gas and Electric Company Compensation  Deferral Plan for
          Key Employees,  dated as of April 26, 1991  (incorporated by reference
          to the  Iowa-Illinois  Gas and Electric  Company Annual Report on Form
          10-K  for the  year  ended  December  31,  1991,  Commission  File No.
          1-3573).

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

10.62     Iowa Utilities Board  Settlement  Agreement among  MidAmerican  Energy
          Company, Office of Consumer Advocate, Iowa Energy Consumers,  Aluminum
          Company  of  America,  Deere &  Company,  Cargill  Inc.,  U.S.  Gypsum
          Company,   Interstate   Power   Company   and  IES   Utilities,   Inc.
          (incorporated  by  reference  to  Exhibit  10.16  to  the  MidAmerican
          Funding,  LLC and MidAmerican Energy Company respective Annual Reports
          on the  combined  Form  10-K for the year  ended  December  31,  2000,
          Commission File Nos. 333-90553 and 1-11505, respectively).

                                     -122-
<PAGE>

10.63     Share  Sale  Agreement,  dated as of  August  6,  2001,  among  NPower
          Yorkshire  Limited,  Innogy  Holdings  plc,  CE  Electric  UK plc  and
          Northern  Electric plc  (incorporated by reference to Exhibit 10.63 of
          the Company's  Registration Statement No. 333-101699 dated December 6,
          2002).

10.64     Purchase  Agreement,  dated as of March 7,  2002,  among The  Williams
          Companies,  Inc., Williams Gas Pipeline Company, LLC, Williams Western
          Pipeline Company LLC, Kern River Acquisition,  LLC and the Company, KR
          Holding,  LLC,  KR  Acquisition  1,  LLC  and KR  Acquisition  2,  LLC
          (incorporated  by reference to Exhibit 99.2 to the  Company's  Current
          Report on Form 8-K dated March 28, 2002).

10.65     Stock  Purchase  Agreement,  dated  as of  March 7,  2002,  among  The
          Williams  Companies,  Inc.,  MEHC  Investment,  Inc.  and the  Company
          (incorporated  by reference to Exhibit 99.3 to the  Company's  Current
          Report on Form 8-K dated March 28, 2002).

10.66     Completion Guarantee,  dated as of June 21, 2002, given by the Company
          to Union Bank of California,  Administrative  Agent  (incorporated  by
          reference to Exhibit 99.2 to the Company's  Current Report on Form 8-K
          dated June 27, 2002).

10.67     Purchase  and  Sale  Agreement,  dated as of July  28,  2002,  between
          Dynegy Inc., NNGC Holding Company,  Inc. and the Company (incorporated
          by reference to Exhibit 99.2 to the Company's  Current  Report on Form
          8-K dated July 30, 2002).

21.1      Subsidiaries of the Registrant.

24.1      Power of Attorney.

99.1      Chief Executive Officer's  Certificate  Pursuant to Section 906 of the
          Sarbanes-Oxley Act of 2002.

99.2      Chief Financial Officer's  Certificate  Pursuant to Section 906 of the
          Sarbanes-Oxley Act of 2002.

                                     -123-