Financial Summary                                     EXHIBIT 13

Over  the  last three years ended December 31, 1998,  MidAmerican
Energy Holdings Company, the successor of CalEnergy Company, Inc.
(the  "Company"),  has experienced significant growth.   Revenues
have  risen  at  a compound annual rate of 89% from approximately
$399 million in 1995 to approximately $2,683 million in 1998  and
net   income   available   to   common  stockholders,   excluding
extraordinary  items and the cumulative effect  of  a  change  in
accounting principle, has risen at a compound annual rate of  30%
from  approximately $62.3 million in 1995 to approximately $137.5
million  in  1998.   This significant growth  has  been  achieved
through:   (i)  acquisitions that complement  and  diversify  the
Company's existing business, broaden the geographic locations  of
its   assets  and  enhance  its  competitive  capabilities;  (ii)
enhancement  of  the  financial  and  technical  performance   of
existing  and  acquired  projects;  and  (iii)  development   and
construction of new projects.

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

The  consummation of the MidAmerican Merger was conditioned  upon
receipt  of a number of regulatory and shareholder approvals  and
the  disposition of partial interests in certain of the Company's
power  generating facilities in order to maintain the  qualifying
facilities   status   of   such  independent   power   generating
facilities.  On February 26, 1999, the Company closed the sale of
all  of  its  ownership interests in the Coso Joint  Ventures  to
Caithness  Energy LLC.  The price includes $205 million  in  cash
and  $5  million  in contingent payments plus the  assumption  of
approximately $67.7 million in debt.  On February  8,  1999,  the
Company  created  a  new  subsidiary,  CE  Generation  LLC   ("CE
Generation")  and subsequently transferred its  interest  in  the
Imperial Valley Projects and Gas Projects (both as defined below)
to  CE  Generation.  On March 2, 1999, CE Generation  closed  the
sale  of  $400 million aggregate principal amount of  its  7.416%
Senior  Secured  Bonds due 2018.  On March 3, 1999,  the  Company
closed  the  sale  of  50%  of  its  ownership  interests  in  CE
Generation  to  an  affiliate of El Paso Energy  Corporation  for
approximately  $247 million in cash, $6.5 million  in  contingent
payments and $23.5 million in equity commitments.  Including  the
gross  proceeds  from  the  CE  Generation  debt  offering,   the
aggregate consideration was approximately $677 million.

On  January 2, 1998, the Company completed the purchase of Kiewit
Diversified Group's ("KDG") ownership interest in various project
partnerships  and  common  shares  of  the  Company   (the   "KDG
Acquisition")  for a cash price of approximately $1,160  million,
including  transaction costs.  KDG's ownership  interest  in  the
Company  comprised  20,231,065 shares of common  stock  (assuming
exercise  by KDG of one million options to purchase the Company's
shares),  the 30% interest in Northern Electric plc ("Northern"),
as well as the following minority project interests:  Mahanagdong
(45%), Casecnan (35%), Dieng (47%), Patuha (44%), Bali (30%)  and
other interests in international development stage projects.

On  December 24, 1996, CE Electric UK plc ("CE Electric"),  which
was  then  70%  owned  indirectly by the Company  and  30%  owned
indirectly by KDG, acquired majority ownership of the outstanding
ordinary  share  capital of Northern pursuant to a  tender  offer
(the "Northern Tender Offer") commenced in the United Kingdom  on
November  5, 1996.  As of March 18, 1997, CE Electric effectively
owned 100% of Northern's ordinary shares.

In  the  last three years, the Company has consummated two  other
significant  acquisitions, in addition  to  the  acquisitions  of
MidAmerican,  KDG  and  Northern.  In  April  1996,  the  Company
completed  the  buy-out  for approximately  $70  million  of  its
partner's  interests ("Partnership Interest")  in  four  electric
generating  plants  in  Southern California,  resulting  in  sole
ownership  of the Imperial Valley Project.  In August  1996,  the
Company   acquired  Falcon  Seaboard  Resources,  Inc.   ("Falcon
Seaboard")  for  approximately $226  million,  thereby  acquiring
significant  ownership  in 520 MW of natural  gas-fired  electric
production facilities located in New York, Texas and Pennsylvania
and a related gas transmission pipeline.
<PAGE>
The  Company  had  actual outstanding shares of 62.1  million  at
December  31,  1997  after adjusting for the  purchase  of  KDG's
shares  on January 2, 1998.  During 1998, the Company repurchased
2.7  million  shares  as  part  of a corporate  stock  repurchase
program.  The Company's actual outstanding shares at December 31,
1998  was  59.6  million  and was further reduced  by  additional
repurchases in 1999 of approximately 786,000 shares resulting  in
actual outstanding shares of approximately 58.8 million at  March
29, 1999.
<PAGE>
SELECTED Financial Data
In Thousands, Except Per Share Amounts
<TABLE>
<CAPTION>
                                          Year Ended December 31,
                                  1998(1)      1997       1996(2)      1995(3)     1994
<S>                            <C>           <C>         <C>         <C>         <C>         
Income Statement Data:
Operating revenue              $2,555,206    $2,166,338    $518,934    $335,630    $154,562
Total revenue                   2,682,711     2,270,911     576,195     398,723     185,854
Expenses                        2,410,658     2,074,051     435,791     301,672     130,018
Income before provision for 
  income taxes                    272,053       196,860(4)  140,404      97,051      55,836
Minority interest                  41,276        45,993       6,122       3,005         ---
Income before change in 
  accounting principle and 
  extraordinary item              137,512        51,823     492,461      63,415      38,834
Extraordinary item, net of tax     (7,146)     (135,850)        ---         ---      (2,007)
Cumulative effect of change in
  accounting principle, net of tax (3,363)          ---         ---         ---         ---
Net income (loss)                 127,003       (84,027)    492,461      63,415      36,827
Preferred dividends                   ---           ---         ---       1,080       5,010
Net income (loss) available to
  common stockholders             127,003       (84,027)    492,461      62,335      31,817
Income per share before change in
  accounting principle and
  extraordinary item            $    2.29       $  0.77(4) $   1.69     $  1.32     $  1.02
Extraordinary item per share        (0.12)        (2.02)        ---         ---       (0.06)
Cumulative effect of change in
  accounting principle per share    (0.06)          ---         ---         ---         ---
Net income (loss) per share     $    2.11       $ (1.25)(4) $  1.69     $  1.32     $  0.96
Basic common shares outstanding    60,139        67,268      54,739      47,249      33,189
Income per share before extraordinary
  item and cumulative effect of
  change in accounting - diluted$    2.15       $ 0.754     $  1.54     $  1.22     $  0.95
Extraordinary item - diluted        (0.10)        (1.97)        ---         ---       (0.05)
Cumulative effect of change in
  accounting principle - diluted    (0.04)          ---         ---         ---         ---
Net income (loss) per 
  share - diluted               $    2.01       $ (1.22)(4) $  1.54     $  1.22     $  0.90
Diluted shares outstanding         74,100        68,686      65,072      56,195      39,203

Balance Sheet Data:
Total assets                   $9,103,524    $7,487,626  $5,630,156  $2,654,038  $1,131,145
Total liabilities               7,598,040     5,282,162   4,181,052   2,084,474     867,703
Company-obligated mandatorily
 redeemable convertible preferred
 securities of subsidiary trusts  553,930       553,930     103,930         ---         ---
Preferred securities of 
 subsidiary                        66,033        56,181     136,065         ---         ---
Minority interest                     ---       134,454     299,252         ---         ---
Redeemable preferred stock            ---           ---         ---         ---      63,600
Stockholders' equity              827,053       765,326     880,790     543,532     179,991
</TABLE>
(1) Reflects the acquisition of KDG.
(2) Reflects the acquisitions of Northern, Falcon Seaboard and the
Partnership Interest owned for a portion of the year.
(3) Reflects the acquisition of Magma Power Company owned for a
portion of the year.
(4) Includes the $87,000, $1.29 per basic share, $1.27 per diluted
share, non-recurring Indonesian asset impairment
   charge.
<PAGE>
MANAGEMENT'S Discussion and Analysis of Financial Condition
and Results of Operations

The  following is management's discussion and analysis of certain
significant  factors which have affected the Company's  financial
condition  and results of operations during the periods  included
in  the  accompanying statements of operations and do not include
any results from MidAmerican. The Company's actual results in the
future  will  differ significantly from the Company's  historical
results due to the MidAmerican Merger.

Acquisitions

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

The  consummation of the MidAmerican Merger was conditioned  upon
receipt  of a number of regulatory and shareholder approvals  and
the  disposition of partial interests in certain of the Company's
power  generating facilities in order to maintain the  qualifying
facilities   status   of   such  independent   power   generating
facilities.  On February 26, 1999, the Company closed the sale of
all  of  its  ownership interests in the Coso Joint  Ventures  to
Caithness  Energy  LLC ("Caithness").  The  price  includes  $205
million  in cash and $5 million in contingent payments  plus  the
assumption  of approximately $67.7 million in debt.  On  February
8,  1999, the Company created a new subsidiary, CE Generation LLC
("CE  Generation") and subsequently transferred its  interest  in
the  Imperial Valley Projects and Gas Projects (both  as  defined
below)  to CE Generation.  On March 2, 1999, CE Generation closed
the sale of $400 million aggregate principal amount of its 7.416%
Senior  Secured  Bonds due 2018.  On March 3, 1999,  the  Company
closed  the  sale  of  50%  of  its  ownership  interests  in  CE
Generation  to  an  affiliate of El Paso Energy  Corporation  for
approximately  $247 million in cash, $6.5 million  in  contingent
payments and $23.5 million in equity commitments.  Including  the
gross  proceeds  from  the  CE  Generation  debt  offering,   the
aggregate consideration was approximately $677 million.

On  January 2, 1998, the Company completed the purchase of Kiewit
Diversified Group's ("KDG") ownership interest in various project
partnerships  and  common  shares  of  the  Company   (the   "KDG
Acquisition")  for a cash price of approximately $1,160  million,
including  transaction costs.  KDG's ownership  interest  in  the
Company  comprised  20,231,065 shares of common  stock  (assuming
exercise  by KDG of one million options to purchase the Company's
shares), a 30% interest in Northern Electric plc ("Northern"), as
well  as  the  following minority project interests:  Mahanagdong
(45%), Casecnan (35%), Dieng (47%), Patuha (44%), Bali (30%)  and
other interests in international development stage projects.

On  December 24, 1996, CE Electric UK plc ("CE Electric"),  which
was  then  70%  owned  indirectly by the Company  and  30%  owned
indirectly by KDG, acquired majority ownership of the outstanding
ordinary  share  capital of Northern pursuant to a  tender  offer
(the "Northern Tender Offer") commenced in the United Kingdom  on
November  5, 1996.  As of March 18, 1997, CE Electric effectively
owned 100% of Northern's ordinary shares.

In  the  last three years, the Company has consummated two  other
significant  acquisitions, in addition  to  the  acquisitions  of
MidAmerican,  KDG  and  Northern.  In  April  1996,  the  Company
completed  the  buy-out  for approximately  $70  million  of  its
partner's  interests ("Partnership Interest")  in  four  electric
generating  plants  in  Southern California,  resulting  in  sole
ownership  of the Imperial Valley Project.  In August  1996,  the
Company   acquired  Falcon  Seaboard  Resources,  Inc.   ("Falcon
Seaboard")  for  approximately $226  million,  thereby  acquiring
significant  ownership  in 520 MW of natural  gas-fired  electric
production facilities located in New York, Texas and Pennsylvania
and a related gas transmission pipeline.
<PAGE>
Power Generation Projects

For  purposes  of  consistency in financial  presentation,  plant
capacity   factors  for  Navy  I,  Navy  II,   and   BLM   plants
(collectively  the  "Coso Project"), are  based  upon  a  nominal
capacity  amount  of  80  net MW for each plant.  Plant  capacity
factors  for  the Vulcan, Hoch (Del Ranch), Elmore  and  Leathers
plants  (collectively with CE Turbo currently under construction,
the "Partnership Project"), are based on nominal capacity amounts
of  34,  38, 38, and 38 net MW, respectively, and for the  Salton
Sea  I,  Salton Sea II, Salton Sea III and Salton Sea  IV  plants
(collectively with Salton Sea V currently under construction, the
"Salton  Sea Project"), are based on nominal capacity amounts  of
10,  20,  49.8  and  39.6 net MW, respectively  (the  Partnership
Project  and the Salton Sea Project are collectively referred  to
as  the  "Imperial Valley Project"). Plant capacity  factors  for
Saranac,  Power  Resources, NorCon and Yuma plants  (collectively
the  "Gas Plants") are based on capacity amounts of 240, 200,  80
and  50  net MW, respectively.  Each plant possesses an operating
margin which allows for production in excess of the amount listed
above.  Utilization  of this operating margin  is  based  upon  a
variety  of  factors and can be expected to vary  throughout  the
year under normal operating conditions.

See  Note 5 to the financial statements for a discussion  of  the
Company's significant operating contracts.

Results  of Operations Three Years Ended December 31, 1998,  1997
and 1996

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

The  increase  in operating revenues in 1997 to $2,166.3  million
from $518.9 million in 1996 was primarily due to the acquisitions
of  Northern,  Falcon Seaboard and the Partnership  Interest,  as
well  as  the  commencement of earnings at Salton Sea  IV,  Upper
Mahiao and Malitbog.

The   following  data  represents  the  supply  and  distribution
operations at Northern:

                                     1998       1997        1996


Electricity Supply (GWh)            15,313     14,378      14,185
Electricity Distribution (GWh)      15,904     15,714      15,656
Gas Supply (Therms in millions)      359.5       74.5        50.0


The  increase  in electricity supplied reflects the  increase  in
contract  volumes in the competitive greater than 100 kW  market.
The less than 100 kW market began opening on a national basis  by
area  in September 1998.  The increase in electricity distributed
in  1998  from  1997  reflects increased activity  in  the  local
economy.  The increase in gas supplied in 1998 from 1997 reflects
the  increased volume as the domestic gas supply business in  the
U.K. opened up to competition beginning in November 1997.

The  following  operating data represents the aggregate  capacity
and electricity production of the domestic geothermal projects:

                                     1998       1997        1996


Overall capacity factor              100.2%     101.4%      104.4%
kWh produced (in thousands)       4,454,500  4,507,500   4,502,200
Capacity NMW (average)                507.4      507.4       491.0*

* Weighted average for the commencement of operations at Salton
Sea IV in 1996.
<PAGE>
The  capacity  factor was 105.4% in the fourth  quarter  of  1998
compared  to  105.1%, 96.4% and 93.8% for the third,  second  and
first  quarters  of  1998,  respectively.   The  capacity  factor
decreased   in  1998  from  1997  due  to  marginally  decreasing
production at the Coso Project and scheduled turbine overhauls at
BLM, Elmore, Leathers and Salton Sea.

The  following  operating data represents the aggregate  capacity
and electricity production of the Gas Plants:


                                    1998           1997            1996

Overall capacity factor             81.6%          84.3%           84.2%
kWh  produced (in thousands)    4,072,620      4,211,030       4,216,800
Installed capacity NMW                570            570             570

The  capacity  factor of the Gas Plants reflects  the  effect  of
certain  contractual curtailments.  The capacity factors adjusted
for these contractual curtailments are 92.2%, 95.7% and 93.2% for
1998, 1997 and 1996, respectively.  The capacity factor decreased
in 1998 from 1997 primarily due to the severe winter snow and ice
storms which caused transmission curtailments at Saranac, as well
as a turbine overhaul at PRI.

Interest  and  other income increased in 1998 to  $127.5  million
from $104.6 million in 1997, a 21.9% increase.  This increase was
due primarily to interest earned by Casecnan on the cash held for
construction, interest earned on the proceeds of the senior  note
and  bond offering and the dividends received from our investment
in  Teesside  Power  Limited, partially offset  by  lower  equity
earnings  due to the consolidation of Mahanagdong equity interest
in  1998.  Interest and other income increased in 1997 to  $104.6
million  from  $57.3 million in 1996 primarily  due  to  interest
earned  by Northern, equity earnings from Saranac and Mahanagdong
and  increased interest income on the proceeds of the equity  and
senior note offerings in October 1997.

Cost of sales increased to $1,258.5 million in 1998 from $1,055.2
million  in  1997.   This  increase is primarily  due  to  higher
volumes of gas and electricity supplied.  Cost of sales increased
to $1,055.2 million in 1997 from $31.8 million in 1996 due to the
acquisition  of  Northern.   Cost of  sales  in  1996  represents
Northern's  costs  of  electricity  during  the  period  of   the
Company's controlling interest since December 24, 1996.

Operating expense increased to $425.0 million in 1998 from $345.8
million in 1997, an increase of 22.9%.  This increase is  due  to
an  increase in Northern's customer acquisition costs,  including
commissions  and opening meter reads associated with the  opening
of   the   competitive  gas  supply  market.   Operating  expense
increased to $345.8 million in 1997 from $132.7 million in  1996,
an  increase of 160.7%. The increase is a result of the Northern,
Falcon  Seaboard  and the Partnership Interest  acquisitions,  as
well as the commencement of receipt of revenue at Salton Sea  IV,
Upper Mahiao and Malitbog.

General  and administration costs decreased to $46.4  million  in
1998  from  $52.7  million in 1997, a decrease  of  12.0%.   This
decrease is due to the integration of Northern's corporate  costs
and other corporate reductions.  General and administration costs
increased to $52.7 million in 1997 from $21.5 million in 1996, an
increase  of 145.7%. This increase is primarily a result  of  the
addition of Northern.

Depreciation and amortization increased to $333.4 million in 1998
from  $276.0 million in 1997, an increase of 20.8%. This increase
is due to the commencement of operations at Mahanagdong and Units
II  and  III  at  Malitbog and the amortization of the  allocated
purchase  price  and  goodwill related to  the  KDG  Acquisition.
Depreciation and amortization increased in 1997 to $276.0 million
from $118.6 million in 1996, a 132.8% increase. This increase  is
primarily  due to the Northern, Partnership Interest  and  Falcon
Seaboard  acquisitions,  and the commencement  of  operations  at
Salton Sea IV, Upper Mahiao and Malitbog.

As   a   result  of  the  KDG  Acquisition,  Casecnan  is   fully
consolidated  into  the Company's financial statements  beginning
January  2,  1998  and  is  no  longer  recorded  as  an   equity
investment.
<PAGE>
Interest expense, less amounts capitalized, increased in 1998  to
$347.3 million from $251.3 million in 1997, a 38.2% increase, and
increased to $251.3 million in 1997 from $126.0 million in  1996,
a 99.4% increase. Higher interest expense is primarily due to the
consolidation of Casecnan resulting from the KDG Acquisition, the
greater average outstanding debt, the discontinued capitalization
of  interest due to the commencement of operations at Mahanagdong
and   Units   II   and  III  at  Malitbog  and  the  discontinued
capitalization  of  interest in Indonesia  as  a  result  of  the
suspension of construction activity.

The  non-recurring charge of $87.0 million in 1997 represents  an
asset  valuation  impairment under Financial Accounting  Standard
No.  121,  "Accounting for the Impairment of Long-Lived  Assets,"
relating  to  the  Company's assets  in  Indonesia.   The  charge
includes all reasonably estimated cash flows associated with  the
Company's  assets in Indonesia and gives effect to the  political
risk  insurance on such investments.  The estimate assumes  there
will  be  no  tax  benefits associated with the  asset  valuation
impairment.

The provision for income taxes decreased to $93.3 million in 1998
from  $99.0  million in 1997 and increased from $41.8 million  in
1996.  After  adjusting for the non-recurring  charge  for  asset
valuation  impairment and the dividends on convertible  preferred
securities, the effective tax rate was 39.5%, 38.0% and 30.8%  in
1998, 1997 and 1996, respectively. The increase from 1996 to 1997
is  due  primarily  to  larger energy tax credits  and  depletion
deductions  in 1996.  The decrease from 1997 to 1998  is  due  to
lower  pretax book income which resulted from increased dividends
on convertible preferred securities of subsidiary trusts.

Minority  interest decreased to $41.3 million in 1998 from  $46.0
million in 1997, a decrease of 10.3%.  Minority interest consists
of  dividends  on convertible preferred securities of  subsidiary
trusts  and  Northern  and  Luzon's  preferred  dividends.   This
decrease  is  a  result  of the purchase of  Northern  and  KDG's
minority  interest,  partially offset by increased  dividends  on
convertible preferred securities of subsidiary trusts.   Minority
interest increased to $46.0 million in 1997 from $6.1 million  in
1996,   primarily  due  to  increased  dividends  on  convertible
preferred securities of subsidiary trusts and  minority  interest
in Northern.

Income  before extraordinary item and cumulative effect of change
in  accounting principle was $137.5 million or $2.29 per share in
1998  compared to $51.8 million or $0.77 per share  in  1997  and
$92.5  million  or $1.69 per share in 1996. Excluding  the  $87.0
million,  $1.29  per share, non-recurring charge,  income  before
extraordinary item would have been $138.8 million  or  $2.06  per
share in 1997.

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

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

Liquidity and Capital Resources

The  Company has available a variety of sources of liquidity  and
capital  resources, both internal and external.  These  resources
provide  funds  required  for  current  operations,  construction
expenditures, debt retirement and other capital requirements.

Cash and short-term investments were $1,604.5 million at December
31,  1998  as compared to $1,445.3 million at December 31,  1997.
<PAGE>
In  addition, the Company recorded separately restricted cash and
investments of $637.6 million and $223.6 million at December  31,
1998   and  1997,  respectively.  The  restricted  accounts   are
comprised  primarily of amounts deposited in restricted  accounts
from  which  the  Company  will fund the various  projects  under
construction.   Additionally,  the  accounts  include  the  Dieng
Project  and  the  Patuha Project restricted cash  accounts;  the
Power   Resources   Project,  the  Upper  Mahiao   Project,   the
Mahanagdong  Project and the Malitbog Project cash  reserves  for
the  debt  service  reserve funds; and the Coso  Project  royalty
payment.

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

The  consummation of the MidAmerican Merger was conditioned  upon
receipt of a number of regulatory and shareholder approvals.   In
addition, the disposition of partial interests in certain of  the
Company's power generating facilities was required prior  to  the
consummation  of the MidAmerican Merger in order to maintain  the
qualifying facilities status of such independent power generating
facilities.

On  January 29, 1999, the Company commenced a cash offer for  all
of  its outstanding Limited Recourse Notes.  The company received
tenders  from  holders  of  an aggregate  of  $195.8  million  in
principal amount of Notes which were paid on March 3, 1999, at  a
redemption price of 110.025% plus accrued interest.

On  February 26, 1999, the Company closed the sale of all of  its
indirect  ownership  interests in  the  Coso  Joint  Ventures  to
Caithness.   The  price  includes $205 million  in  cash  and  $5
million   in   contingent  payments  plus   the   assumption   of
approximately $67.7 million in debt.

On  February  8,  1999, the Company created a new subsidiary,  CE
Generation  and  subsequently transferred  its  interest  in  the
Imperial  Valley Projects and Gas Projects to CE Generation.   On
March  2,  1999,  CE Generation closed the sale of  $400  million
aggregate principal amount of its 7.416% Senior Secured Bonds due
2018.   On March 3, 1999, the Company closed the sale of  50%  of
its  ownership interests in CE Generation to an affiliate  of  El
Paso  Energy Corporation for approximately $247 million in  cash,
$6.5  million in contingent payments and $23.5 million in  equity
commitments.  Including the gross proceeds from the CE Generation
debt offering, the aggregate consideration was approximately $677
million.

On  March  11,  1999,  MidAmerican Funding, LLC,  a  wholly-owned
subsidiary  of the Company, issued $200 million of  5.85%  Senior
Secured  Notes  due 2001, $175 million of 6.339%  Senior  Secured
Notes  due 2009, and $325 million of 6.927% Senior Secured  Bonds
due  2029.  The proceeds from the offering were used to  complete
the MidAmerican Merger.

During  the  last  quarter of 1998, the Company  repurchased  and
retired  $160.1  million of the Company's 10.25% Senior  Discount
Notes at an average price of 106.173% plus accrued interest.  The
remainder of the Senior Discount Notes were subsequently redeemed
on  January  15,  1999  at a redemption price  of  105.125%  plus
accrued interest.

On  September 22, 1998, the Company issued $1.4 billion of Senior
Notes  and Bonds.  The securities are made up of $215 million  of
6.96%  Senior Notes due 2003, $260 million of 7.23% Senior  Notes
due  2005, $450 million of 7.52% Senior Notes due 2008  and  $475
million of 8.48% Senior Bonds due 2028.  Interest is payable semi-
annually  on March 15 and September 15, commencing on  March  15,
1999.   The securities are subject to optional redemption at  any
time  at  par plus payment of a make-whole premium.  The proceeds
from the  offering  were used in part to complete the MidAmerican
Merger  and  to  refinance the Company's 10.25%  Senior  Discount
Notes.
<PAGE>
On  November 13, 1998, the Company issued $100 million  of  7.52%
Series  B  Senior  Notes  due 2008.  Interest  is  payable  semi-
annually  on  March 15 and September 15 commencing on  March  15,
1999.   The securities are subject to optional redemption at  any
time  at  par plus a make-whole premium.  The proceeds  from  the
offering  were used in part to complete the MidAmerican Merger.

On   April  8,  1998,  the  Company's  affiliates  converted  the
construction project financing for its Malitbog geothermal  power
project   to   term  loans.   The  Overseas  Private   Investment
Corporation  ("OPIC") is providing term loan financing  of  $54.9
million that was fixed as of June 15, 1998 at an interest rate of
9.176%.   A  syndicate  of  international  commercial  banks   is
providing  term  loan financing of $98.9 million  at  a  variable
interest  rate based on LIBOR (7.47% at December 31, 1998).   The
loans have scheduled repayments through June 2005.

On   May   5,  1998,  the  Company's  affiliates  converted   the
construction  project financing for its Upper  Mahiao  geothermal
power  project to term loans.  Export-Import Bank of  the  United
States  ("Ex-Im Bank") is providing term loan financing of $140.7
million  at  a  fixed  interest rate of  5.95%.   United  Coconut
Planters Bank of the Philippines is providing term loan financing
of $9.4 million at a variable interest rate based on LIBOR (8.25%
at  December  31,  1998).   The loans have  scheduled  repayments
through June 2006.

On   June  18,  1998,  the  Company's  affiliates  converted  the
construction  project  financing for its  Mahanagdong  geothermal
power  project to term loans.  Ex-Im Bank is providing term  loan
financing  of $175.2 million at a fixed rate of 6.92%.   OPIC  is
providing term loan financing of $38.9 million that was fixed  as
of  September  30, 1998 at an interest rate of 7.6%.   The  loans
have scheduled repayments through June 2007.

In  November 1995, CE Casecnan Water and Energy Company, Inc.,  a
Philippine Corporation ("CE Casecnan") which is expected to be at
least  70%  indirectly owned by the Company, closed the financing
and  commenced construction of the Casecnan Project,  a  combined
irrigation and 150 net MW hydroelectric power generation  project
(the  "Casecnan  Project") located in the  central  part  of  the
island of Luzon in the Republic of the Philippines.

CE  Casecnan  entered into a fixed-price, date  certain,  turnkey
engineering,  procurement and construction contract  to  complete
the   construction  of  the  Casecnan  Project   (the   "Casecnan
Construction   Contract").    The   work   under   the   Casecnan
Construction   Contract  is  being  conducted  by  a   consortium
consisting of Cooperativa Muratori Cementisti CMC di Ravenna  and
Impresa  Pizzarotti & C. Spa working together with Siemens  A.G.,
Sulzer  Hydro Ltd., Black & Veatch and Colenco Power  Engineering
Ltd.   Construction  of the Casecnan Project is  expected  to  be
completed in 2000.  No further equity funding is expected.

The  Company  developed  and owns the  rights  to  a  proprietary
process  for the extraction of minerals from elements in solution
in  the  geothermal  brine and fluids utilized  at  its  Imperial
Valley  plants (the "Salton Sea Extraction Project") as  well  as
the production of power to be used in the extraction process.   A
pilot plant has successfully produced commercial quality zinc  at
the  Company's Imperial Valley Project.  The Company  intends  to
sequentially develop facilities for the extraction of  manganese,
silver,  gold,  lead,  boron, lithium and other  products  as  it
further develops the extraction technology.  The Company is  also
investigating  producing silica from the solids precipitated  out
of  the geothermal power process.  Silica is used as a filler for
such products as paint, plastics and high temperature cement.

Minerals LLC, an indirect wholly-owned subsidiary of the Company,
is constructing the Zinc Recovery Project which will recover zinc
from   the   geothermal  brine  (the  "Zinc  Recovery  Project").
Facilities  will  be installed near the Imperial  Valley  Project
sites  to  extract a zinc chloride solution from  the  geothermal
brine  through  an ion exchange process.  This solution  will  be
transported to a central processing plant where zinc ingots  will
be   produced  through  solvent  extraction,  electrowinning  and
casting processes.  The Zinc Recovery Project is designed to have
a  capacity of approximately 30,000 metric tonnes per year and is
scheduled to commence commercial operation in mid-2000.  The zinc
produced  by  the Zinc Recovery Project is expected  to  be  sold
primarily  to U.S. West Coast customers such as steel  companies,
alloyers and galvanizers.
<PAGE>
The  Zinc Recovery Project is being constructed by Kvaerner  U.S.
Inc.  ("Kvaerner")  pursuant  to  a  date  certain,  fixed-price,
turnkey  engineering, procurement and construction contract  (the
"Zinc  Recovery Project EPC Contract").  Kvaerner  is  a  wholly-
owned  indirect  subsidiary of Kvaerner ASA,  an  internationally
recognized engineering and construction firm experienced  in  the
metals, mining and processing industries.  Total project costs of
the Zinc Recovery Project are expected to be approximately $200.9
million.   The Company has incurred $24.2 million of  such  costs
through December 31, 1998.

Power  LLC, an indirect wholly owned subsidiary of CE Generation,
is  constructing Salton Sea V. Salton Sea V will be a 49  net  MW
geothermal power plant which will sell approximately one-third of
its  net output to the Zinc Recovery Project.  The remainder will
be sold through the California Power Exchange ("PX").

Salton  Sea  V  is being constructed pursuant to a date  certain,
fixed  price,  turnkey engineering, procurement and  construction
contract  (the  "Salton Sea V EPC Contract") by Stone  &  Webster
Engineering  Corporation ("SWEC"). SWEC is  one  of  the  world's
leading  engineering and construction firms for the  construction
of  electric  power plants and, in particular,  geothermal  power
plants.   Salton  Sea  V  is  scheduled  to  commence  commercial
operation in mid-2000.  Total project costs of Salton Sea  V  are
expected to be approximately $119.1 million.

Turbo  LLC, an indirect wholly-owned subsidiary of CE Generation,
is  constructing the CE Turbo Project. The CE Turbo Project  will
have  a  capacity of 10 net MW.  The net output of the  CE  Turbo
Project will be sold to the Zinc Recovery Project or sold through
the PX.

The  Partnership Projects propose to upgrade the geothermal brine
processing  facilities at the Vulcan and Del Ranch Projects  with
the  Region  2  Brine Facilities Construction.   In  addition  to
incorporating  the  pH Modification Process,  which  has  reduced
operating  costs at the Salton Sea Projects, the  more  efficient
facilities  are expected to achieve additional economies  through
improved  brine  processing systems and the utilization  of  more
modern   equipment.   The  Partnership  Projects   expect   these
improvements  will reduce brine-handling operating costs  at  the
Vulcan Project and the Del Ranch Project.

The   CE   Turbo  Project  and  the  Region  2  Brine  Facilities
Construction  are being constructed by SWEC pursuant  to  a  date
certain,  fixed  price,  turnkey  engineering,  procurement   and
construction contract (the "Region 2 Upgrade EPC Contract").  The
obligations   of  SWEC  are  guaranteed  by  Stone   &   Webster,
Incorporated.   The  CE  Turbo Project is scheduled  to  commence
initial  operations in mid-2000 and the Region 2 Brine Facilities
Construction  is scheduled to be completed in early-2000.   Total
project  costs  for both the CE Turbo Project and  the  Region  2
Brine  Facilities  Construction are expected to be  approximately
$63.7 million.

On  October 13, 1998, the Salton Sea Funding Corporation, then an
indirect wholly owned subsidiary of the Company, completed a sale
to  institutional investors of $285 million aggregate  amount  of
7.475% Senior Secured Series F Bonds due November 30, 2018, which
are  nonrecourse to the Company.  The proceeds from the  offering
will  be  used to fund construction of the Zinc Recovery Project,
Salton  Sea  Unit  V, the CE Turbo Project, the  Region  2  Brine
Facilities  Construction,  additional  capital  improvements  and
financing  costs.   Total equity funding for  these  projects  is
expected  to  be approximately $122.5 million, of which  El  Paso
will contribute $23.5 million for its share on the Salton Sea  V,
CE Turbo and Region 2 Brine Facilities Construction.

On  January 2, 1998, the Company completed the purchase of Kiewit
Diversified Group's ("KDG") ownership interest in various project
partnerships  and  common  shares  of  the  Company   (the   "KDG
Acquisition")  for a cash price of approximately $1,160  million,
including  transaction costs.  KDG's ownership  interest  in  the
Company  comprised  20,231,065 shares of common  stock  (assuming
exercise  by KDG of one million options to purchase the Company's
shares),  a  30% interest in Northern, as well as  the  following
minority  project interests: Mahanagdong (45%),  Casecnan  (35%),
Dieng  (47%),  Patuha (44%), Bali (30%) and  other  interests  in
international  development stage projects.   The  Company  funded
this  acquisition  with available cash and the  proceeds  of  the
equity and senior note offerings completed in October 1997.
<PAGE>
On  December  2,  1994,  subsidiaries of  the  Company,  Himpurna
California  Energy  Ltd. ("HCE") and Patuha Power,  Ltd.  ("PPL",
together   with  HCE,  the  "Indonesian  Subsidiaries")  executed
separate  joint  operation contracts for the development  of  the
geothermal steam field and geothermal power facilities located in
Central Java in Indonesia with Perusahaan Pertambangan Minyak Dan
Gas  Bumi  Negara  ("Pertamina"),  the  Indonesian  national  oil
company,   and  executed  separate  "take-or-pay"  energy   sales
contracts with both Pertamina and P.T. PLN (Persero) ("PLN"), the
Indonesian   national  electric  utility.   The   Government   of
Indonesia provided sovereign guarantees of the obligations  under
the joint operating and "take-or-pay" contracts.

In  1997  and 1998 a series of Indonesian government decrees  and
other  actions (including the non-payment of all monthly invoices
from  HCE's Dieng Unit I, which became operational in March 1998)
have  created significant uncertainty as to whether PLN  and  the
Indonesian government will honor their contractual obligations to
the Indonesian Subsidiaries.  The Indonesian Subsidiaries in 1998
initiated  dispute  resolution  procedures  under  the  ESCs  and
sovereign guarantees with PLN and the Government of Indonesia and
subsequently  commenced arbitration to resolve  the  dispute  and
they intend to continue to take actions to require the Government
of  Indonesia  to  honor  its contractual obligations.   However,
actions  by  the Government of Indonesia have created significant
risks   to  the  Indonesian  Subsidiaries.   Dieng  Unit  I   was
operationally and contractually completed in March 1998 when  the
"take-or-pay" obligations under its contract with PLN  commenced.
However,  PLN  has  defaulted on the contractually  required  and
sovereign    guaranteed   "take-or-pay"   payment    obligations.
Accordingly,   the   arbitration   is   proceeding   before    an
international arbitration panel, as provided under the Indonesian
Subsidiaries' contracts with PLN.  The arbitration involves  both
PLN  and  the Government of Indonesia and is expected to conclude
in the third quarter of 1999.

Within  the  United  Kingdom there was  continued  investment  to
extend   and   improve  the  electricity  distribution   network.
Expenditures  in  1998  were approximately $93  million  although
customers directly contributed approximately $31 million  to  the
additional  costs incurred in expanding the system to meet  their
specific requirements.

The  Company  repurchased 21.9 million common shares during  1998
for the aggregate amount of $703.5 million, primarily as a result
of   the   KDG   acquisition  in  which  the  company   purchased
approximately 19.2 million shares of treasury stock.  The Company
repurchased  1.6  million  common  shares  during  1997  for  the
aggregate amount of $55.5 million.  As of December 31,  1998  the
Company  held 23.4 million shares of treasury stock at a cost  of
$752.2  million.   The treasury shares will  provide  shares  for
issuance  under  the Company's employee stock  option  and  share
purchase plan and other outstanding convertible securities.   The
repurchase  plan minimizes the dilutive effect of the  additional
shares issued under these plans.

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

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

Inflation  has  not  had a substantial impact  on  the  Company's
operating revenues and costs; energy payments for electricity for
the  Leathers Project, Salton Sea II Project and Salton  Sea  III
Project  will continue to be based upon scheduled rates  and  are
not  adjusted for inflation through the initial ten  year  period
after  the  dates  of  firm operation under each  power  purchase
agreement.

What  is generally known as the year 2000 ("Y2K") computer  issue
arose  because  many  existing  computer  programs  and  embedded
systems  use  only  the  last two digits  to  refer  to  a  year.
Therefore,  those  computer programs do not properly  distinguish
between  a  year that begins with "20" instead of "19".   If  not
corrected,  many  computer  applications  could  fail  or  create
erroneous  results.  The failure to correct a material  Y2K  item
could  result  in  an interruption in, or a failure  of,  certain
normal   business   activities  or   operations   including   the
generation,  distribution,  and  supply  of  electricity.    Such
failures  could  materially and adversely  affect  the  Company's
results of operations, liquidity and financial condition.

The  Y2K issue creates uncertainty for the Company from potential
issues with its own computer systems and from third parties  with
whom  the Company deals on transactions worldwide.  The Company's
operations  utilize  systems  and  equipment  provided  by  other
organizations.  As a result, Y2K readiness of suppliers, vendors,
service   providers  or  customers  could  impact  the  Company's
operations.   The  Company is assessing  the  readiness  of  such
constituent entities and the impacts on those entities that  rely
upon  the Company's services.  The Company is unable to determine
at  this  time whether the consequences of Y2K failures of  third
parties  will have a material impact on the Company's results  of
operations, liquidity or financial condition.

The Company has commenced, for all of its information systems,  a
Y2K  date  conversion  project  to  address  all  necessary  code
changes, testing and implementation in order to resolve  the  Y2K
issue.   The  Company  created a worldwide Y2K  project  team  to
identify,  assess  and correct all of its information  technology
(IT)  and  non-IT systems, as well as, identify and assess  third
party   systems.   The  Company  has  identified   and   assessed
substantially all of its IT and non-IT systems and  is  currently
in  the process of repairing or replacing those systems which  it
believes  are not Year 2000 compliant.  As of December 31,  1998,
the  Company  was  approximately 91%  complete  in  repairing  or
replacing those systems.  The Company expects to be 100% complete
of  correcting,  testing,  and compliance  of  those  systems  by
October 1999.

Total  Y2K  expenditures, for both repairing  or  replacing  non-
compliant  systems,  are  expected to total  approximately  $12.6
million.   As  of  December 31, 1998, the  Company  had  incurred
approximately $3.9 million of Y2K expenditures.  The  Company  is
not aware of any additional material costs necessary to bring all
of  its  systems into compliance; however, there is no  assurance
that additional costs will not be incurred.

Although  management  believes  that  the  Y2K  project  will  be
substantially  complete before January 1,  2000,  any  unforeseen
failures of the Company's and/or third parties' computer  systems
could  have a material impact on the Company's ability to conduct
its  business.  Accordingly, the Company is developing  a  formal
contingency  plan that is expected to be completed  by  mid  year
1999 to mitigate any potential business interruption.

Recent Accounting Pronouncements

In  June  1998,  the  FASB issued SFAS No. 133,  "Accounting  for
Derivative Instruments and Hedging Activities," which established
accounting and reporting standards for derivative instruments and
for hedging activities.  It requires that an entity recognize all
derivatives  as either assets or liabilities in the statement  of
financial  position and measure those instruments at fair  value.
<PAGE>
This  statement  is effective for all fiscal quarters  of  fiscal
years  beginning  after June 15, 1999.  The  Company  is  in  the
process   of   evaluating   the   impact   of   this   accounting
pronouncement.

Qualitative and Quantitative Disclosures About Market Risk

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

Interest Rate Risk

At  December 31, 1998, the Company had fixed-rate long-term  debt
and    Company-obligated   mandatorily   redeemable   convertible
preferred securities of subsidiary trusts of $5,712.3 million  in
principal  amount  and having a fair value of  $6,049.9  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 $265 million if interest  rates
were  to increase by 10% from their levels at December 31,  1998.
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, 1998, the Company had floating-rate obligations
of  $581.4  million  which expose the  Company  to  the  risk  of
increased  interest expense in the event of increases  in  short-
term  interest  rates.   However, the Company  has  entered  into
interest  rate  swap agreements for the purpose of  offsetting  a
portion  of  such interest rate fluctuations. The  interest  rate
differential  is  reflected as an adjustment to interest  expense
over  the  life of the instruments.  At December 31, 1998,  these
interest  rate  swaps had an aggregate notional amount  of  $90.5
million,  which  the  Company  could  terminate  at  a  cost   of
approximately  $9.9 million.  A decrease of 10% in  the  December
31,  1998  level  of interest rates would increase  the  cost  of
terminating  the  swaps  by  approximately  $1.5  million.    The
termination  costs of swap agreements would impact the  Company's
earnings  and  cash flows only if all or a portion  of  the  swap
instruments were terminated prior to their expiration.    If  the
floating  rates  were to increase by 10% from December  31,  1998
levels,  the Company's consolidated interest expense for unhedged
floating-rate   obligations  would  increase   by   approximately
$270,000  each month in which such increase continued based  upon
December 31, 1998 principal balances.

Currency Exchange Rate Risk

At  December 31, 1998, CE Electric UK Funding Company had  fixed-
rate  obligations  denominated in U.S. dollars  which  expose  CE
Electric  UK Funding Company to losses in the event of  increases
in the exchange rate of U.S. dollars to Sterling.  CE Electric UK
Funding   Company  entered  into  certain  interest   rate   swap
agreements  that  effectively  convert  the  U.S.  dollar   fixed
interest rate to a fixed rate in Sterling. At December 31,  1998,
these  interest  rate swap agreements had an  aggregate  notional
amount  of $362 million, which the Company could terminate  at  a
cost  of  approximately $20 million.  A decrease of  10%  in  the
December  31, 1998 rate of exchange of Sterling to dollars  would
increase  the  cost  of  terminating  these  swap  agreements  by
approximately $53 million.

Energy Commodity Price Risk

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

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

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

(i)  The CFD is not closed in advance of its agreed term.

(ii) The  level  of  purchase  occurs as expected,  matching  the
     volumes covered by the CFD.

Therefore,  disclosure in respect to CFD relies on the assumption
that  the  contracts  exist  in  parallel  to  underlying  actual
electricity  purchases.  In the absence  of  such  purchases  the
contract  would  generate a loss or gain dependent  on  the  pool
prices prevailing over the periods covered by the contract  term.
As of December 31, 1998, the notional amount of executed CFDs was
approximately $936.3 million, representing approximately  19%  of
the  expected or committed transaction volumes through March  31,
2004.   The fair value of these contracts was approximately $83.0
million  discounted at 15%, based upon quoted  market  prices  at
December 31, 1998.  A hypothetical decrease of 10% in the  market
price  of  electricity from the December 31,  1998  levels  would
decrease  the fair value of these contracts by approximately  $91
million.  However, as stated above, the value of the portfolio of
CFDs  which  are  held for risk management purposes  is  directly
linked  to  the hypothetical changes in Pool price, such  that  a
movement  in Pool price would be offset by a compensating  impact
on the contract.

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

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

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

As  of  December  31,  1998, the notional amount  of  outstanding
forward  purchase  contracts  was  approximately  $96.8  million,
representing  approximately 50% of expected sales  through  March
31,  2000.   The  fair value of such contracts was  approximately
$(13.8)  million  discounted at 15%,  based  upon  quoted  market
prices  at December 31, 1998.  A hypothetical decrease of 10%  in
the  market price of gas from the December 31, 1998 levels  would
further   decrease   the  fair  value  of  these   contracts   by
approximately $8 million.

Certain  information  included in this report  contains  forward-
looking  statements  made  pursuant  to  the  Private  Securities
Litigation  Reform Act of 1995 ("Reform Act").   Such  statements
are  based on current expectations and involve a number of  known
and  unknown risks and uncertainties that could cause the  actual
results and performance of the Company to differ materially  from
any expected future results or performance, expressed or implied,
by  the forward-looking statements.  In connection with the  safe
harbor  provisions of the Reform Act, the Company has  identified
important  factors  that  could cause actual  results  to  differ
materially   from   such   expectations,  including   development
uncertainty,   operating  uncertainty,  acquisition  uncertainty,
uncertainties  relating to doing business outside of  the  United
States,   uncertainties   relating   to   geothermal   resources,
uncertainties  relating  to domestic and  international  (and  in
particular,  Indonesian)  economic and political  conditions  and
uncertainties  regarding  the impact of regulations,  changes  in
government   policy,  industry  deregulation   and   competition.
Reference  is made to all of the Company's SEC filings, including
the   Company's  Report  on  Form  8-K  dated  March  26,   1999,
incorporated  herein  by reference, for  a  description  of  such
factors.  The Company assumes no responsibility to update forward-
looking information contained herein.
<PAGE>
CONSOLIDATED BALANCE SHEETS
As of December 31, 1998 and 1997
Dollars and Shares in Thousands, Except Per Share Amounts

ASSETS                                                   1998          1997


Cash and cash equivalents                             $1,604,470    $1,445,338
Joint venture cash and investments                         1,678         6,072
Restricted cash                                          515,231       223,636
Restricted investments                                   122,340           ---
Accounts receivable                                      528,116       376,745
Properties, plants, contracts and equipment, net       4,236,039     3,528,910
Excess of cost over fair value of net assets 
  acquired, net                                        1,538,176     1,312,788
Equity investments                                       125,036       238,025
Deferred charges and other assets                        432,438       356,112

Total assets                                          $9,103,524    $7,487,626

LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable                                      $  305,757    $  173,610
Other accrued liabilities                              1,009,091     1,106,641
Parent company debt                                    2,645,991     1,303,845
Subsidiary and project debt                            3,093,810     2,189,007
Deferred income taxes                                    543,391       509,059

Total liabilities                                      7,598,040     5,282,162

Deferred income                                           58,468        40,837

Commitments and contingencies (Notes 3, 17, 18 and 19)
Company - obligated mandatorily redeemable
 convertible preferred securities of subsidiary trusts   553,930       553,930
Preferred securities of subsidiary                        66,033        56,181
Minority interest                                            ---       134,454
Common stock and options subject to redemption               ---       654,736

Stockholders' equity:
Preferred stock - authorized 2,000 shares, no par value      ---           ---
Common stock - par value $.0675 per share,
 authorized 180,000 shares, issued 82,980 shares, 
 outstanding 59,605 and  81,322 shares, respectively       5,602         5,602
Additional paid in capital                             1,233,088     1,261,081
Retained earnings                                        340,496       213,493
Accumulated other comprehensive income                        45        (3,589)
Common stock and options subject to redemption               ---      (654,736)
Treasury stock - 23,375 and 1,658 common shares at cost (752,178)      (56,525)

Total stockholders' equity                               827,053       765,326

Total liabilities and stockholders' equity            $9,103,524    $7,487,626

The accompanying notes are an integral part of these financial statements.
<PAGE>
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Years Ended December 31, 1998
Dollars and Shares in Thousands, Except Per Share Amounts

                                              1998         1997        1996

Revenue:
Operating revenue                         $2,555,206   $2,166,338   $  518,934
Interest and other income                    127,505      104,573       57,261

Total revenues                             2,682,711    2,270,911      576,195

Costs and expenses:
Cost of sales                              1,258,539    1,055,195       31,840
Operating expense                            425,004      345,833      132,655
General and administration                    46,401       52,705       21,451
Depreciation and amortization                333,422      276,041      118,586
Loss on equity investment in Casecnan            ---        5,972        5,221
Interest expense                             406,084      296,364      165,900
Less interest capitalized                    (58,792)     (45,059)     (39,862)
Non-recurring charge - asset valuation 
  impairment                                     ---       87,000          ---

Total costs and expenses                   2,410,658    2,074,051      435,791

Income before provision for income taxes     272,053      196,860      140,404
Provision for income taxes                    93,265       99,044       41,821

Income before minority interest              178,788       97,816       98,583
Minority interest                             41,276       45,993        6,122

Income before extraordinary item and
 cumulative effect of change in
 accounting principle                        137,512       51,823       92,461
Extraordinary item, net of tax                (7,146)    (135,850)         ---
Cumulative effect of change in
 accounting principle, net of tax             (3,363)         ---          ---
Net income (loss) available to 
  common stockholders                     $  127,003    $ (84,027)    $ 92,461

Income per share before extraordinary item
 and cumulative effect of change in
 accounting principle                     $     2.29    $    0.77     $   1.69

Extraordinary item                             (0.12)       (2.02)         ---
Cumulative effect of change in
 accounting principle                          (0.06)         ---          ---
Net income (loss) per share               $     2.11    $   (1.25)    $   1.69

Income per share before extraordinary item
 and cumulative effect of change in
 accounting principle - diluted           $     2.15    $    0.75     $   1.54
Extraordinary item - diluted                   (0.10)       (1.97)         ---
Cumulative effect of change in
 accounting principle - diluted                (0.04)         ---          ---
Net income (loss) per share - diluted     $     2.01    $   (1.22)    $   1.54


The accompanying notes are an integral part of these financial
statements.
<PAGE>
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Three Years Ended December 31, 1998
Dollars and Shares in Thousands
<TABLE>
<CAPTION>
                                                       Accumulated Common Stock
                 Outstanding      Additional              Other     & Options
                    Common Common   Paid-In Retained Comprehensive Subject to Treasury Unearned
                    Shares  Stock   Capital Earnings      Income    Redemption  Stock Compensation Total
<S>                 <C>    <C>    <C>        <C>       <C>        <C>       <C>         <C>      <C>
Balance 
 December 31, 1995  50,593 $3,421 $  343,406 $205,059  $    ---   $    ---  $  (1,348)  $(7,006) $543,532

Net income             ---    ---        ---   92,461       ---        ---        ---       ---    92,461
Foreign currency translation 
 adjustment*           ---    ---        ---      ---    29,658        ---        ---       ---    29,658
Comprehensive income                                                                              122,119

Exercise of stock options 
 and other equity 
 transactions        5,263    337     53,030      ---       ---        ---      4,569     1,535    59,471
Purchase of treasury 
 stock                (472)   ---        ---      ---       ---        ---    (12,008)      ---   (12,008)
Conversion of debt   8,064    545    164,912      ---       ---        ---        ---       ---   165,457
Tax benefit from 
 stock plan            ---    ---      2,219      ---       ---        ---        ---       ---     2,219

Balance December 
 31, 1996           63,448  4,303    563,567  297,520    29,658        ---     (8,787)   (5,471)  880,790

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

Equity offering     19,100  1,289    697,315      ---       ---        ---        ---       ---   698,604
Exercise of stock 
 options and other 
 equity transactions   396     10     (2,757)     ---       ---        ---      7,767     5,471    10,491
Purchase of treasury 
 stock              (1,622)   ---        ---      ---       ---        ---    (55,505)      ---   (55,505)
Common stock and 
 options subject 
 to redemption         ---    ---        ---      ---       ---   (654,736)       ---       ---  (654,736)
Tax benefit from 
 stock plan            ---    ---      2,956      ---       ---        ---        ---       ---     2,956

Balance December 
  31, 1997          81,322  5,602  1,261,081  213,493    (3,589)  (654,736)   (56,525)      ---   765,326

Net income             ---    ---        ---  127,003       ---        ---        ---       ---   127,003
Foreign currency 
translation adjustment*---    ---        ---      ---     3,634        ---        ---       ---     3,634
Comprehensive income                                                                              130,637

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

Balance December 
 31, 1998           59,605 $5,602 $1,233,088 $340,496     $  45   $   ---  $(752,178)    $  ---  $827,053
</TABLE>

*  Foreign currency translation adjustment has no tax effect

The accompanying notes are an integral part of these financial statements.
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Years Ended December 31, 1998
Dollars in Thousands

                                                1998           1997       1996
Cash flows from operating activities:
Net income (loss)                          $  127,003    $   (84,027)  $ 92,461
Adjustments to reconcile net cash flow 
 from operating activities:
  Non-recurring charge-asset 
   valuation impairment                           ---         87,000        ---
  Extraordinary item, net of tax                7,146            ---        ---
  Cumulative effect of change in 
   accounting principle                         3,363            ---        ---
  Depreciation and amortization               290,794        239,234    109,447
  Amortization of excess of cost over fair
   value of net assets acquired                42,628         36,807      9,139
  Amortization of original
   issue discount                                  42          2,160     50,194
  Amortization of deferred
   financing  and other costs                  21,681         31,632     11,212
  Provision for deferred income
   taxes                                       34,332         55,584     12,252
  Income on equity investments                (10,837)       (16,068)      (910)
  Income (loss) applicable to 
   minority interest                            5,313        (35,387)     1,431
  Changes in other items:
    Accounts receivable                      (135,124)       (34,146)   (13,936)
    Accounts payable, accrued 
     liabilities and deferred income          (41,803)        29,799      2,093
Net cash flows from operating activities      344,538        312,588    273,383
Cash flows from investing activities:
Purchase of KDG, Northern, Falcon Seaboard, 
 Partnership Interest, and Magma, net of 
 cash acquired                               (500,916)      (632,014)  (474,443)
Distributions from equity investments          17,008         23,960      8,222
Capital expenditures relating to 
  operating projects                         (227,071)      (194,224)   (24,821)
Philippine construction                      (112,263)       (27,334)  (167,160)
Indonesian construction                       (83,869)      (146,297)   (76,546)
Acquisition of  U.K. gas assets               (35,677)           ---        ---
Domestic construction and other 
  development costs                           (36,047)       (12,794)   (73,179)
Decrease in short-term investments              1,282          2,880     33,998
Decrease (increase) in restricted 
  cash and investments                         20,568       (116,668)    63,175
Other                                         (33,787)        60,390     (2,910)
Net cash flows from investing activities     (990,772)    (1,042,101)  (713,664)
Cash flows from financing activities:
Proceeds from sale of common and treasury stock
 and exercise of stock options                  3,412        703,624     54,935
Proceeds from convertible preferred 
  securities of subsidiary trusts                 ---        450,000    103,930
Proceeds from issuance of parent 
  company debt                              1,502,243        350,000    324,136
Repayment of parent company debt             (167,285)      (100,000)       ---
Net proceeds from revolver                        ---        (95,000)    95,000
Proceeds from subsidiary and project debt     464,974        795,658    428,134
Repayments of subsidiary and project debt    (255,711)      (271,618)  (210,892)
Deferred charges relating to debt financing   (47,205)       (48,395)   (36,010)
Purchase of treasury stock                   (724,791)       (55,505)   (12,008)
Other                                          21,701         13,142     10,756
Net cash flows from financing activities      797,338      1,741,906    757,981
Effect of exchange rate changes                 3,634        (33,247)     4,860
Net increase in cash and cash equivalents     154,738        979,146    322,560
Cash and cash equivalents at beginning 
  of year                                   1,451,410        472,264    149,704
Cash and cash equivalents at end of year   $1,606,148     $1,451,410   $472,264
Supplemental Disclosures:
Interest paid (net of amounts capitalized) $  341,645      $ 316,060   $ 92,829
Income taxes paid                          $   53,609      $  44,483   $ 23,211

     The accompanying notes are an integral part of these
financial statements.
<PAGE>
NOTES To Consolidated Financial Statements
For the Three Years Ended December 31, 1998
Dollars, Pounds and Shares in Thousands, Except Per Share Amounts

1. Business

MidAmerican  Energy Holdings Company, the successor  to  CalEnergy
Company,  Inc.  (the  "Company"), is a United States-based  global
power   company   which   generates,  distributes   and   supplies
electricity  to  utilities, government entities, retail  customers
and  other  customers located throughout the world.   Through  its
subsidiaries  the Company is primarily engaged in the development,
ownership and operation of environmentally responsible independent
power   production  facilities  worldwide  utilizing   geothermal,
natural gas, hydroelectric and other energy sources.  In addition,
the   Company  through  its  subsidiary,  Northern  Electric   plc
("Northern")  is  engaged  in  the  distribution  and  supply   of
electricity  to approximately 1.5 million customers  primarily  in
northeast  England  as  well  as  the  generation  and  supply  of
electricity  (together  with  other related  business  activities)
throughout  England  and  Wales.   Northern  is  also  active   in
supplying gas and has approximately 550,000 customers on supply in
England, Wales and Scotland.

Northern  is  one  of  the twelve regional  electricity  companies
("RECs")   which  came  into  existence  as  a   result   of   the
restructuring  and  subsequent privatization  of  the  electricity
industry  in  the  United Kingdom in 1990.   Northern's  principal
business is the distribution of electricity in its authorized area
located  in  northeast  England which covers approximately  14,400
square  kilometers  and  has  a population  of  approximately  3.2
million  people.   As  a  regional  platform,  Northern's  related
activities also include:  (i)  the supply of electricity  and  gas
inside  and  outside  its  authorized  area,  and  (ii)  ownership
interests  in  producing  gas fields in the  North  Sea  and  gas,
transmission  and  storage  operations.   Consisitent   with   the
Company's  goals, these related activities serve  to  support  the
operations  and  growth of the Northern electric  and  gas  supply
business.

2. Summary of Significant Accounting Policies

The  consolidated financial statements include the accounts of the
Company,  its  wholly-owned subsidiaries,  and  its  proportionate
share  of the partnerships and joint ventures in which it  has  an
undivided interest in the assets and is proportionally liable  for
its  share of liabilities.  Other investments and corporate  joint
ventures 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 as of the date of each acquisition.

Cash Equivalents, Investments and Restricted Cash

The Company considers all investment instruments purchased with an
original  maturity of three months or less to be cash equivalents.
Restricted cash is not considered a cash equivalent.

Investments  other  than restricted cash are primarily  commercial
paper  and  money market securities. The restricted  cash  balance
includes  such securities and mortgage backed securities,  and  is
mainly  composed of amounts deposited in restricted accounts  from
which  the Company will source its equity contributions  and  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.

At  December  31,  1998,  all  of the  Company's  investments  are
classified  as  held-to-maturity and are accounted  for  at  their
amortized  cost  basis.  The carrying amount  of  the  investments
approximates  the  fair  value based on quoted  market  prices  as
provided by the financial institution which holds the investments.
<PAGE>


Properties, Plants, Contracts, Equipment and Depreciation

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

Depreciation  of the operating power plant costs, net  of  salvage
value,  is computed on the straight line method over the estimated
useful  lives, between 10 and 30 years. Depreciation of furniture,
fixtures and equipment which are recorded at cost, is computed  on
the  straight line method over the estimated useful lives  of  the
related assets, which range from three to ten years.

The KDG, Northern, Falcon Seaboard, Partnership Interest and Magma
acquisitions  by the Company have been accounted for  as  purchase
business  combinations.   All  identifiable  assets  acquired  and
liabilities  assumed  were  assigned a  portion  of  the  cost  of
acquiring  the respective companies equal to their fair values  at
the date of the acquisition and include the following:

     Property and equipment of Northern is depreciated  using
     a  systematic  method, which approximates  the  straight
     line  method  over  the estimated useful  lives  of  the
     related assets which range from 3-60 years.
     
     Power sales agreements are amortized separately over (1)
     the remaining portion of the scheduled price periods  of
     the  power  sales agreements and (2) for the Partnership
     Interest and Magma acquisitions the 20 year avoided cost
     periods of the power sales agreements using the straight
     line method.

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

Expenditures   on   major  information  technology   systems   are
capitalized  and  depreciated on a straight line  basis  over  the
useful life of the developed systems which range from 3-10 years.

In April 1998, the Accounting Standards Executive Committee issued
Statement of Position (SOP) No. 98-5, "Reporting on the  Costs  of
Start-Up  Activities."   SOP  No.  98-5  requires  that,  at   the
effective   date   of  adoption,  costs  of  start-up   activities
previously  capitalized be expensed and reported as  a  cumulative
effect  of a change in accounting principle, and further  requires
that  such  costs subsequent to adoption be expensed as  incurred.
The  Company adopted this standard in 1998 and expensed applicable
unamortized start-up costs previously capitalized.  The cumulative
effect  of the change in accounting principle was $3,363,  net  of
taxes of $2,196.

Well, Resource Development and Exploration Costs

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

Total  acquisition costs in excess of the fair values assigned  to
the  net  assets acquired are amortized  using the  straight  line
method  over  a  40  year  period  for  the  Northern  and   Magma
acquisitions, a 25 year period for the Falcon Seaboard acquisition
and a 32 year period for the KDG acquisition.

Impairment of Long-Lived Assets

The  Company  reviews  long-lived assets and certain  identifiable
intangibles   for  impairment  whenever  events  or   changes   in
circumstances indicate that the carrying amount of  an  asset  may
not  be  recoverable.   An  impairment loss  would  be  recognized
whenever   evidence  exists  that  the  carrying  value   is   not
recoverable.

Deferred Well and Rework Costs

Well  rework  costs are deferred and amortized over the  estimated
period  between reworks. These deferred costs, net of  accumulated
amortization, are $6,769 and $5,421 at December 31, 1998 and 1997,
respectively, and are included in other assets.

Revenue Recognition

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

Capitalization of Interest and Deferred Financing Costs

Prior  to  the commencement of operations, interest is capitalized
on the costs of the construction projects and resource development
to  the  extent incurred. Capitalized interest and other  deferred
charges are amortized over the lives of the related assets.

Deferred  financing  costs are amortized  over  the  term  of  the
related financing using the effective interest method.

Deferred Income Taxes

The  Company recognizes deferred tax assets and liabilities  based
on the difference between the financial statement and tax bases of
assets and liabilities using estimated tax rates in effect for the
year  in  which  the  differences are expected  to  reverse.   The
Company intends to repatriate earnings of foreign subsidiaries  in
the  foreseeable future.  As a result, deferred income  taxes  are
provided  for retained earnings of international subsidiaries  and
corporate joint ventures which are intended to be remitted.

Pensions

Northern contributes to the Electricity Supply Pension Scheme  and
contributions  to the scheme are charged to the income  statement.
The  capital  cost  of  ex gratia and supplementary  pensions  are
normally  charged to the income statement in the period  in  which
they   are  granted.   Variations  in  pension  cost,  which   are
identified  as  a  result  of  actuarial  valuations/reviews,  are
amortized  over  the average expected remaining working  lives  of
employees   in   proportion  to  their  expected  payroll   costs.
Differences between the amounts funded and the amounts charged  to
the  profit  and loss account are treated as a prepayment  in  the
balance sheet.

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

A  reconciliation of basic earnings per share before extraordinary
item  and  cumulative effect of change in accounting principle  to
diluted   earnings  per  share  before  extraordinary   item   and
cumulative effect of change in accounting principle follows:
<TABLE>
<CAPTION>
                                          1998                   1997                   1996
                                             Per-Share               Per-Share               Per-Share
                            Income   Shares   Amount   Income  Shares  Amount  Income  Shares  Amount
<S>                       <C>        <C>      <C>     <C>      <C>      <C>    <C>      <C>     <C> 
Basic earnings per share 
 before extraordinary
 item and cumulative 
 effect of change in
 accounting principle     $137,512   60,139   $2.29   $51,823  67,268   $0.77  $92,461  54,739  $1.69
Effect of dilutive 
 securities Stock options      ---      634               ---     1,418            ---   1,881  
Convertible preferred 
 securities of subsidiary 
 trusts(1)                  21,883   13,327               ---       ---          2,840   2,517
Convertible debt               ---      ---               ---       ---          4,968   5,935
Diluted earnings per share 
 before extraordinary
 item and cumulative 
 effect of change in
 accounting principle     $159,395  74,100    $2.15   $51,823    68,686 $0.75 $100,269  65,072  $1.54
</TABLE>
(1)  The  convertible preferred securities of subsidiary  trusts  were
antidilutive in 1997.

Financial Instruments

The  Company  utilizes swap agreements, contracts for  differences
and  forward purchase agreements to manage market risks and reduce
its exposure resulting from fluctuation in interest rates, foreign
currency exchange rates and electric and gas prices.  For interest
rate swap agreements, the net cash amounts paid or received on the
agreements are accrued and recognized as an adjustment to interest
expense.  For contracts for differences, the net cash amounts paid
or  received  on the agreements are accrued and recognized  as  an
adjustment  to  cost of sales.  Gains and losses  related  to  gas
forward contracts are deferred and included in the measurement  of
the  related gas purchases.  The Company's practice is not to hold
or  issue  financial  instruments  for  trading  purposes.   These
instruments  are either exchange traded or with counterparties  of
high credit quality; therefore, the risk of nonperformance by  the
counterparties is considered to be negligible.

Foreign Currency Translation

For the Company's foreign operations whose functional currency  is
not  the  U.S.  dollar, the assets and liabilities are  translated
into  U.S.  dollars at current exchange rates,  and  revenues  and
expenses  are translated at average exchange rates for  the  year.
Resulting  translation  adjustments are reflected  as  a  separate
component of stockholders' equity.

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

Reclassification

Certain  amounts in the fiscal 1997 and 1996 financial  statements
and  supporting  footnote disclosures have  been  reclassified  to
conform to the fiscal 1998 presentation. Such reclassification did
not impact previously reported net income or retained earnings.
<PAGE>
Use of Estimates

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

New Accounting Pronouncement

In  June  1998, the Financial Accounting Standards Board  ("FASB")
issued  Statement  of Financial Accounting Standard  ("SFAS")  No.
133,   "Accounting   for   Derivative  Instruments   and   Hedging
Activities," which established accounting and reporting  standards
for  derivative  instruments  and  for  hedging  activities.    It
requires that an entity recognize all derivatives as either assets
or  liabilities in the statement of financial position and measure
those instruments at fair value.  This statement is effective  for
the Company in the first quarter of the year 2000.  The Company is
in  the  process  of  evaluating the  impact  of  this  accounting
pronouncement.

3.  MidAmerican Merger

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

The  consummation  of the MidAmerican Merger was conditioned  upon
receipt  of a number of regulatory and shareholder approvals.   In
addition, regulatory approval required the disposition of  partial
interests in certain of the Company's independent power generating
facilities prior to the consummation of the MidAmerican Merger  in
order  to maintain the qualifying facilities status of such  power
generating facilities.  See Note 21.

The  MidAmerican  Merger  will  be accounted  for  as  a  purchase
business combination and as such the results of operations of  the
Company  will  include the results of MidAmerican beginning  March
12, 1999.

4. Acquisitions

KDG

On  January 2, 1998, the Company completed the purchase of  Kiewit
Diversified Group's ("KDG") ownership interest in various  project
partnerships   and  common  shares  of  the  Company   (the   "KDG
Acquisition")   for   a   cash  price  of  $1,160,215,   including
transaction  costs.   KDG's  ownership  interest  in  the  Company
comprised  approximately 20,231 shares of common  stock  (assuming
exercise  by KDG of one million options to purchase the  Company's
shares),  a  30%  interest in Northern, as well as  the  following
minority  project  interests: Mahanagdong (45%),  Casecnan  (35%),
Dieng  (47%),  Patuha  (44%), Bali (30%) and  other  interests  in
international development stage projects.

The  KDG Acquisition has been accounted for as a purchase business
combination.   All  identifiable assets acquired  and  liabilities
assumed  were  assigned a portion of the cost of  acquiring  KDG's
interests,  equal  to  their  fair  values  at  the  date  of  the
acquisition.   The total cost of the acquisition was allocated  as
follows:

Cash                                                      $       4,563
Investment in operating projects                                 49,868
Investment in construction and development projects              71,095
<PAGE>
Accrued liabilities                                              (7,331)
Deferred income taxes                                             1,299
Minority interest                                               134,454
Additional paid in capital (stock options)                       21,313
Treasury stock                                                  633,423
Excess  of cost over fair value of net assets acquired          251,531

                                                             $1,160,215

As  many  of the projects were not operational in 1997, pro  forma
combined  revenue, income before extraordinary items,  net  income
and  basic  earnings per share of the Company and KDG's  interests
for  the  twelve  months  ended  December  31,  1997,  as  if  the
acquisition  had  occurred at the beginning of 1997  after  giving
effect   to   certain  pro  forma  adjustments  related   to   the
acquisition, was not materially different from actual results.

Northern

On December 24, 1996, CE Electric UK plc ("CE Electric"), which in
1997  was  70%  owned  indirectly by the  Company  and  30%  owned
indirectly  by KDG, acquired majority ownership of the outstanding
ordinary share capital of Northern pursuant to a tender offer (the
"Northern  Tender  Offer")  commenced in  the  United  Kingdom  on
November 5, 1996.  As of March 18, 1997, CE Electric owned 100% of
Northern's ordinary shares.

Falcon Seaboard

On August 7, 1996, the Company completed the acquisition of Falcon
Seaboard for a cash price of $229,500 including acquisition costs.
Through   the   acquisition,  the  Company   indirectly   acquired
significant  ownership  interests  in  three  operating  gas-fired
cogeneration facilities and a related natural-gas pipeline.    The
plants  are located in Texas, Pennsylvania and New York and  total
520 MW in capacity.

Edison Mission Energy's Partnership Interest

On April 17, 1996, the Company completed the acquisition of Edison
Mission   Energy's  Partnership  Interests  in   four   geothermal
operating  facilities in California for a cash purchase  price  of
$71,000  including acquisition costs.   The four projects, Vulcan,
Hoch (Del Ranch), Leathers and Elmore, are located in the Imperial
Valley of California.  Prior to this transaction, the Company  was
a 50% owner of these facilities.

5.Properties, Plants, Contracts and Equipment

Properties, plants, contracts and equipment comprise the following
at December 31:

                                                   1998     1997

Distribution system                            $1,305,806  $1,237,743
Power plants                                    1,868,002   1,481,679
Wells and resource development                    473,237     395,314
Power sales agreements                            193,868     193,868
Other assets                                      313,029     269,973

Total operating assets                          4,153,942   3,578,577
Less accumulated depreciation and amortization   (769,526)   (495,959)
<PAGE>
Net operating assets                            3,384,416   3,082,618
Mineral and gas reserves, net                     375,208     297,048
Construction in progress:
  Casecnan                                        243,948         ---
  Indonesia                                       190,175     140,172
  Zinc recovery project, Salton Sea 
        V and other                                42,292       9,072

 Total                                         $4,236,039  $3,528,910


Coso Project Operating Facilities

The  Coso  Project  operating facilities  comprise  the  Company's
proportionate  share  of the assets of three  of  its  Coso  Joint
Ventures:   Coso  Finance Partners ("Navy I Joint Venture"),  Coso
Energy Developers ("BLM Joint Venture"), and Coso Power Developers
("Navy  II  Joint  Venture").  Under terms of  the  Navy  I  Joint
Venture,  current profits and losses were allocated 46.4%  to  the
Company.  The BLM power plant is situated on lands leased from the
U.S.  Bureau of Land Management under a geothermal lease agreement
that extends until October 31, 2035. The lease may be extended  to
2075  at  the option of the BLM. Under the terms of the BLM  Joint
Venture  agreement, the Company's share of profits and losses  was
48%.   Under  terms  of  the Navy II Joint Venture,  all  profits,
losses  and capital contributions for Navy II were divided equally
by the two partners.  See Note 21.

The  Coso Joint Ventures had royalty expense included in operating
expenses  of  $12,608,  $13,458 and $13,412  in  the  years  ended
December 31, 1998, 1997 and 1996, respectively.

Imperial Valley Project Operating Facilities

The  Imperial  Valley Project consists of the Partnership  Project
and  the  Salton  Sea  Project located in the Imperial  Valley  in
California.  The  operating Partnership Project  consists  of  the
Vulcan, Hoch (Del Ranch), Elmore, and Leathers Partnerships.   The
operating  Salton Sea Project consist of Salton Sea I, Salton  Sea
II,  Salton Sea III and Salton Sea IV.  See Note 21.  The Imperial
Valley  Project commencement dates and nominal capacities  are  as
follows:

  Imperial Valley            Commencement           Nominal
      Plants                     Date              Capacity
   Vulcan                 February 10, 1986           34  MW
   Hoch (Del Ranch)       January 2, 1989             38  MW
   Elmore                 January 1, 1989             38  MW
   Leathers               January 1, 1990             38  MW
   Salton Sea I           July 1, 1987                10  MW
   Salton Sea II          April 5, 1990               20  MW
   Salton Sea III         February 13, 1989          49.8 MW
   Salton Sea IV          May 24, 1996               39.6 MW

The  Partnership  Project  pays royalties  based  on  both  energy
revenues  and  total electricity revenues. Hoch  (Del  Ranch)  and
Leathers pay royalties of approximately 5% of energy revenues  and
1%   of  total  electricity  revenue.  Elmore  pays  royalties  of
approximately  5%  of energy revenues. Vulcan  pays  royalties  of
4.167% of energy revenues.

The  Salton Sea Project's weighted average royalty expense in 1998
was  approximately  4.8%.  The  royalties  are  paid  to  numerous
recipients  based on varying percentages of electrical revenue  or
steam production multiplied by published indices.

The  Imperial  Valley  Projects had royalty  expense  included  in
<PAGE>
operating  expenses of $13,328, $14,343 and $10,228 in  the  years
ended December 31, 1998, 1997 and 1996, respectively.

Significant Customers and Contracts

All  of  the Company's sales of electricity from the Coso  Project
and  Imperial Valley Project, which comprise approximately 17%  of
1998  operating revenue, are to Southern California Edison Company
("Edison") and are under long-term power purchase contracts.

The  Coso Project and the Partnership Project sell all electricity
generated by the respective plants pursuant to seven long-term SO4
Agreements  between the projects and Edison. These SO4  Agreements
provide for capacity payments, capacity bonus payments and  energy
payments.  Edison makes fixed annual capacity and  capacity  bonus
payments  to  the  projects to the extent  that  capacity  factors
exceed  certain  benchmarks. The price for capacity  and  capacity
bonus payments is fixed for the life of the SO4 Agreements. Energy
is  sold  at  increasing scheduled rates for the first  ten  years
after  firm operation and thereafter at Edison's Avoided  Cost  of
Energy.

The  scheduled  energy  price periods  of  the  Coso  Project  SO4
Agreements  extended until at least August 1997 for  each  of  the
units  operated  by the Navy I Partnership and  extends  until  at
least  March 1999 and January 2000 for each of the units  operated
by  the  BLM and Navy II Partnerships, respectively. The Company's
share  of  aggregate  annual  capacity payments  is  approximately
$17,000 and its share of aggregate bonus payments is approximately
$3,000.

The  scheduled energy price periods of the Partnership Project SO4
Agreements extended until February 1996 for Vulcan, December  1998
for Hoch (Del Ranch) and Elmore and extend until December 1999 for
the  Leathers  Partnership.   The  annual  capacity  payments  are
approximately  $24,500  and the bonus payments  are  approximately
$4,400 in aggregate for the four plants.

For  1999, Navy I, Vulcan, Hoch and Elmore are receiving  Edison's
Avoided   Cost   of  Energy  pursuant  to  their  respective   SO4
Agreements.   The SO4 Agreement for Leathers provides  for  energy
rates of 15.6 cents per kWh in 1999.  The weighted average energy  rate
for Coso Project and the Partnership Project was 11.3 cents per kWh  in
1998.

Salton  Sea  I sells electricity to Edison pursuant to  a  30-year
negotiated power purchase agreement, as amended (the "Salton Sea I
PPA"), which provides for capacity and energy payments. The energy
payment  is  calculated using a Base Price  which  is  subject  to
quarterly  adjustments  based on a basket  of  indices.  The  time
period  weighted average energy payment for Salton Sea I was  5.4 cents
per  kWh  during  1998. As the Salton Sea I  PPA  is  not  an  SO4
Agreement,  the energy payments do not revert to Edison's  Avoided
Cost of Energy.  The capacity payment is approximately $1,100  per
annum.

Salton  Sea  II  and  Salton Sea III sell  electricity  to  Edison
pursuant  to  30-year  modified SO4 Agreements  that  provide  for
capacity  payments, capacity bonus payments and  energy  payments.
The  price  for  contract  capacity and  contract  capacity  bonus
payments is fixed for the life of the modified SO4 Agreements. The
energy  payments for the first ten year period, which  expires  in
April  2000  and  February 1999 are levelized  at  a  time  period
weighted average of 10.6 cents per kWh and 9.8 cents per kWh for Salton  Sea
II  and  Salton  Sea  III, respectively. Thereafter,  the  monthly
energy  payments  will be Edison's Avoided  Cost  of  Energy.  For
Salton Sea II only, Edison is entitled to receive, at no cost,  5%
of  all  energy  delivered in excess of 80% of  contract  capacity
through September 30, 2004. The annual capacity and bonus payments
for  Salton Sea II and Salton Sea III are approximately $3,300 and
$9,700, respectively.

The Salton Sea IV Project sells electricity to Edison pursuant  to
a  modified  SO4  agreement which provides for  contract  capacity
payments on 34 MW of capacity at two different rates based on  the
respective contract capacities deemed attributable to the original
Salton  Sea PPA option (20 MW) and to the original Fish  Lake  PPA
(14  MW). The capacity payment price for the 20 MW portion adjusts
quarterly  based  upon specified indices and the capacity  payment
price for the 14 MW portion is a fixed levelized rate.  The energy
payment  (for deliveries up to a rate of 39.6 MW) is  at  a  fixed
price for 55.6% of the total energy delivered by Salton Sea IV and
is  based  on  an energy payment schedule for 44.4% of  the  total
energy  delivered by Salton Sea IV.  The contract  has  a  30-year
term  but Edison is not required to purchase the 20 MW of capacity
and  energy originally attributable to the Salton Sea I PPA option
after  September 30, 2017, the original termination  date  of  the
Salton Sea I PPA.
<PAGE>
For  the  years ended December 31, 1998 and 1997 Edison's  average
Avoided  Cost of Energy was 3.0 cents and 3.3 cents, respectively,  per  kWh
which is substantially below the contract energy prices earned for
the  year  ended  December 31, 1998. Estimates of Edison's  future
Avoided  Cost of Energy vary substantially from year to year.  The
Company cannot predict the likely level of Avoided Cost of  Energy
prices under the SO4 Agreements and the modified SO4 Agreements at
the  expiration  of  the scheduled payment periods.  The  revenues
generated  by each of the projects operating under SO4  Agreements
will  likely  decline significantly after the  expiration  of  the
respective scheduled payment periods.

Philippine Projects

The  Upper  Mahiao Project was deemed complete in  June  1996  and
began  receiving  capacity payments pursuant to the  Upper  Mahiao
Energy Conversion Agreement ("ECA"), in July of 1996.  The project
is  structured  as  a ten year build-own-operate-transfer  project
("BOOT"),  in  which the Company's subsidiary CE  Cebu  Geothermal
Power   Company,  Inc.  ("CE  Cebu"),  the  project  company,   is
responsible  for providing operations and maintenance  during  the
ten  year  BOOT period.  The electricity generated  by  the  Upper
Mahiao  geothermal power plant is sold to PNOC-Energy  Development
Corporation ("PNOC-EDC"), which is also responsible for  supplying
the  facility  with  the geothermal steam.   After  the  ten  year
cooperation period, and the recovery by the Company of its capital
investment  plus incremental return, the plant will be transferred
to PNOC-EDC at no cost.

PNOC-EDC  is  obligated  to  pay for  electric  capacity  that  is
nominated  each year by CE Cebu, irrespective of whether  PNOC-EDC
is  willing or able to accept delivery of such capacity.  PNOC-EDC
pays  to  CE  Cebu a fee (the "Capacity Fee") based on  the  plant
capacity nominated to PNOC-EDC in any year (which, at the  plant's
design  capacity, is approximately 95% of total contract revenues)
and  a  fee  (the "Energy Fee") based on the electricity  actually
delivered   to  PNOC-EDC  (approximately  5%  of  total   contract
revenues).  Payments under the Upper Mahiao ECA are denominated in
U.S.  dollars, or computed in U.S. dollars and paid in  Philippine
pesos  at  the then-current exchange rate, except for  the  Energy
Fee.  Significant portions of the Capacity Fee and Energy Fee  are
indexed  to  U.S.  and  Philippine inflation rates,  respectively.
PNOC-EDC's  payment requirements, and its other obligations  under
the  Upper  Mahiao  ECA  are supported by the  Government  of  the
Philippines through a performance undertaking.

Unit I of the Malitbog Project (the "Malitbog Project") was deemed
complete  in July 1996 and Units II and III in July 1997 at  which
times  such units commenced receiving capacity payments under  the
Malitbog  ECA.   The  Malitbog Project is owned  and  operated  by
Visayas  Geothermal  Power Company ("VGPC"), a Philippine  general
partnership that is indirectly wholly owned by the Company.  Under
its  contract, VGPC sells 100% of its output on substantially  the
same basis as described above for the Upper Mahiao Project to PNOC-
EDC,  which  in  turn  sells  the  power  to  the  National  Power
Corporation  of the Philippines ("NPC").  However,  VGPC  receives
100%  of  its  revenues from such sales in the  form  of  capacity
payments.  As with the Upper Mahiao Project, the Malitbog  Project
is  structured  as  a  ten  year BOOT, in  which  the  Company  is
responsible for providing operations and maintenance for  the  ten
year  BOOT period.  After a ten year cooperation period,  and  the
recovery by the Company of its capital investment plus incremental
return, the plant will be transferred to PNOC-EDC at no cost.

The  Mahanagdong  Project (the "Mahanagdong Project")  was  deemed
complete  in  July  1997 and accordingly, the Mahanagdong  Project
began receiving capacity payments pursuant to the Mahanagdong  ECA
in  August of 1997.  The Mahanagdong Project is owned and operated
by   CE   Luzon  Geothermal  Power  Company,  Inc.,  a  Philippine
corporation,  that  is  indirectly  owned  by  the  Company.   The
electricity generated by the Mahanagdong Project is being sold  to
PNOC-EDC  on a "take or pay" basis, which is also responsible  for
supplying  the facility with the geothermal steam.  The  terms  of
the  Mahanagdong  ECA are substantially similar to  those  of  the
Upper  Mahiao  ECA.   All  of  PNOC-EDC's  obligations  under  the
Mahanagdong ECA are supported by the Government of the Philippines
through a performance undertaking.  The capacity fees are expected
to  be  approximately 97% of total revenues at the design capacity
levels and the energy fees are expected to be approximately 3%  of
such total revenues.

Gas Projects
<PAGE>
The Saranac Project sells electricity to New York State Electric &
Gas pursuant to a 15-year negotiated power purchase agreement (the
"Saranac  PPA"), which provides for capacity and energy  payments.
Capacity  payments,  which  in 1998  totaled  2.3 cents  per  kWh,  are
received  for electricity produced during "peak hours" as  defined
in the Saranac PPA and escalate at approximately 4.1% annually for
the  remaining  term  of  the  contract.  Energy  payments,  which
averaged  6.7 cents  per  kWh in 1998, escalate at  approximately  4.4%
annually  for the remaining term of the Saranac PPA.  The  Saranac
PPA expires in June 2009.

The  Power  Resources Project sells electricity to Texas Utilities
Electric  Company ("TUEC") pursuant to a 15-year negotiated  power
purchase agreement (the "Power Resources PPA"), which provides for
capacity  and  energy  payments.  Capacity  payments  and   energy
payments,  which in 1998 were $3,138 per month and 3.0 cents  per  kWh,
respectively, escalate at 3.5% annually for the remaining term  of
the  Power  Resources  PPA.  The Power Resources  PPA  expires  in
September 2003.

The  NorCon  Project  sells electricity to  Niagara  Mohawk  Power
Corporation  ("Niagara")  pursuant to a 25-year  negotiated  power
purchase  agreement (the "NorCon PPA") which provides  for  energy
payments  calculated  pursuant to an adjusting  formula  based  on
Niagara's ongoing Tariff Avoided Cost and the contractual Long-Run
Avoided Cost.  The NorCon PPA term extends through December 2017.

The  Yuma  Project sells electricity to San Diego Gas  &  Electric
("SDG&E") under an existing 30-year power purchase contract.   The
energy  is sold at SDG&E's Avoided Cost of Energy and the capacity
is  sold  to  SDG&E  at a fixed price for the life  of  the  power
purchase  contract.  The contract term extends through  May  2024.
The  Company  and  SDG&E  are  currently  engaged  in  discussions
regarding  a potential restructuring or buyout and termination  of
the Yuma PPA.

Roosevelt Hot Springs

The  Company operates and owns an approximately 70% interest in  a
geothermal steam field which supplies geothermal steam to a 23 net
MW  power  plant  owned  by Utah Power &  Light  Company  ("UP&L")
located  on  the  Roosevelt Hot Springs property under  a  30-year
steam sales contract.

The  Company obtained approximately $20,317 cash under a  pre-sale
agreement  with UP&L whereby UP&L paid in advance  for  the  steam
produced by the steam field. The Company must make certain penalty
payments  to  UP&L  if the steam produced does  not  meet  certain
quantity and quality requirements.

Salton Sea Minerals Extraction

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

6. Equity Investments

The  Company has an approximate 45% economic interest  in  Saranac
Power  Partners, L.P. and a 20% economic interest in NorCon  Power
Partners,  L.P.   Summary financial information for  these  equity
investments follows:

                                                       Saranac      NorCon

As of and for the year ended December 31, 1998:
Assets                                               $  300,583 $  114,009
Liabilities                                             198,603    108,444
Net income                                               37,783      6,297
<PAGE>
As of and for the year ended December 31, 1997:
Assets                                               $  315,671 $ 118,415
Liabilities                                             211,299   115,487
Net income                                               43,097     4,072

7.                       Parent Company Debt

 Parent company debt comprises the following at December 31:

                                        1998      1997
Senior Discount Notes              $  369,501  $ 529,640
9.5% Senior Notes                     224,265    224,205
7.63% Senior Notes                    350,000    350,000
Limited Recourse Senior Secured Notes 200,000    200,000
$1.4 Billion Senior Notes           1,400,000        ---
$100 Million Senior Notes             102,225        ---
                                  $ 2,645,991 $1,303,845

Senior Discount Notes

In  March  1994,  the Company issued $400,000 of  10  1/4%  Senior
Discount Notes which accreted to an aggregate principal amount  of
$529,640  at  maturity in 2004.  The original issue  discount  was
amortized  from  the issue date through January 15,  1997,  during
which time no cash interest was paid on the Senior Discount Notes.
Cash   interest   on  the  Senior  Discount  Notes   was   payable
semiannually  on  January 15 and July 15 of each year,  commencing
July  15, 1997.  During 1998,  the Company repurchased and retired
$160,139 of the notes at an average price of 106.173% plus accrued
interest.  The  remainder  of  the  Senior  Discount  Notes   were
subsequently redeemed on January 15, 1999 at a redemption price of
105.125%  plus  accrued interest.  Due to the early extinguishment
of   the   Senior   Discount  Notes,  the  Company   recorded   an
extraordinary item of $7,146, net of tax.

9.5% Senior Notes

On  September 20, 1996, the Company issued $225,000 of 9.5% Senior
Notes  (the  "9.5% Senior Notes") due 2006. Interest on  the  9.5%
Senior Notes is payable semiannually on March 15 and September  15
of  each  year, commencing March 15, 1997.  The 9.5% Senior  Notes
are  redeemable  at  any  time  on or  after  September  15,  2001
initially  at a redemption price of 104.75% declining to  100%  on
September  15,  2004  plus  accrued  interest  to  the   date   of
redemption. The 9.5% Senior Notes are unsecured senior obligations
of the Company.

7.63% Senior Notes

On  October 28, 1997, the Company issued $350,000 of 7.63%  Senior
Notes  (the "7.63% Senior Notes") due 2007.  Interest on the 7.63%
Senior Notes is payable semiannually on April 15 and October 15 of
each year, commencing April 15, 1998.  The 7.63% Senior Notes  are
unsecured senior obligations of the Company.

Limited Recourse Senior Secured Notes

On  July 21, 1995,  the Company issued $200,000 of  9 7/8% Limited
Recourse Senior Secured Notes Due 2003  (the
"Limited Recourse Notes"). Interest on the Limited Recourse  Notes
is  payable  on  June 30 and December 30 of each year,  commencing
December  1995.  The  Limited Recourse Notes  are  secured  by  an
assignment and pledge of 100% of the outstanding capital stock  of
Magma  and  are  recourse only to such Magma  capital  stock,  the
Company's  interest in a secured Magma note and general assets  of
the  Company equal to the Restricted Payment Recourse  Amount,  as
defined in the Note Indenture ("Note Indenture"), which was $0  at
December 31, 1998.  See Note 21.
<PAGE>
On  or  after June 30, 2000, the remaining Limited Recourse  Notes
are  redeemable at the option of the Company, in whole or in part,
initially at a redemption price of 104.9375% declining to 100%  on
June 30, 2002 and thereafter, plus accrued interest to the date of
redemption.

$1.4 Billion Senior Notes

On September 22, 1998, the Company issued $215,000 of 6.96% Senior
Notes  due 2003, $260,000 of 7.23% Senior Notes due 2005, $450,000
of 7.52% Senior Notes due 2008, and $475,000 of 8.48% Senior Bonds
due 2028 (collectively, the "$1.4 Billion Senior Notes"). Interest
on  the $1.4 Billion Senior Notes will be payable semiannually  on
March 15 and September 15 of each year, commencing March 15, 1999.
The  $1.4  Billion Senior Notes are unsecured  senior  obligations
of the Company.

$100 Million Senior Notes

On  November 13, 1998 the Company issued $100,000 at a premium  of
approximately  102.243% of 7.52% Senior Notes (the  "$100  Million
Senior  Notes")  due  2008.  Interest on the $100  Million  Senior
Notes will be payable semiannually on March 15 and September 15 of
each  year,  commencing March 15, 1999.  The $100  Million  Senior
Notes are unsecured senior obligations of the Company.

Revolving Credit Facility

On  July  8,  1996,  the Company obtained a  $100,000  three  year
revolving  credit  facility.  On November  26,  1997,  the  credit
facility  was  amended and increased to $400,000 and  extended  to
November 2000. The facility is unsecured and is available to  fund
working capital requirements and finance future business expansion
opportunities.

8.  Subsidiary and Project Debt

Project  loans  held  by  subsidiaries  and  projects  which   are
nonrecourse to the Company comprise the following at December 31:
                                                  1998       1997

Salton Sea Notes and Bonds                   $   626,816 $   448,754
Northern Eurobonds                               426,785     427,732
CE Electric UK Funding Company Senior Notes      360,070     357,331
CE Electric UK Funding Company Sterling Bonds    324,916     322,534
Power Resources Project Debt                      90,529     103,334
Coso Funding Corp. Project Loans                  67,705     106,616
Casecnan Notes and Bonds                         371,500         ---
Malitbog Loans                                   153,806     176,657
Upper Mahiao Loans                               150,110     150,628
Mahanagdong Loans                                214,082         ---
Northern Short Term Treasury Loan                 72,740         ---
CE Gas Loan                                       41,355         ---
Other                                                918       5,962
CE Indonesia Funding Corp. Construction Loans    192,478      89,459
                                             $ 3,093,810$  2,189,007

Each of the Company's direct or indirect subsidiaries is organized
as  a  legal  entity separate and apart from the Company  and  its
other   subsidiaries.   Pursuant  to  separate  project  financing
agreements,  the  assets  of  each  subsidiary  are   pledged   or
encumbered to support or otherwise provide the security for  their
own project or subsidiary debt.  It should not be assumed that any
asset  of  any  such subsidiary will be available to  satisfy  the
obligations  of the Company or any of its other such subsidiaries;
<PAGE>
provided,  however, that unrestricted cash or other  assets  which
are  available for distribution may, subject to applicable law and
the  terms of financing arrangements of such parties, be advanced,
loaned,  paid as dividends or otherwise distributed or contributed
to  the Company or affiliates thereof. "Subsidiaries" means all of
the Company's direct or indirect subsidiaries (1) owning interests
in  the  Coso, Imperial Valley, Saranac, NorCon, Power  Resources,
Mahanagdong,  Malitbog, Upper Mahiao, Casecnan, Dieng  and  Patuha
projects  or  (2)  owning interests in the subsidiaries  that  own
interests in the foregoing projects.  See Note 21.

Salton Sea Notes and Bonds

The Salton Sea Funding Corporation, an indirectly owned subsidiary
of the Company, (the "Funding Corporation") debt securities are as
follows:
                              Final Maturity      December 31,   December 31,
          Senior Secured Series    Date       Rate    1998           1997
July 21, 1995    A Notes      May 30, 2000    6.69% $ 48,436     $  97,354
July 21, 1995    B Bonds      May 30, 2005    7.37%  106,980       133,000
July 21, 1995    C Bonds      May 30, 2010    7.84%  109,250       109,250
June 20, 1996    D Notes      May 30, 2000    7.02%   12,150        44,150
June 20, 1996    E Bonds      May 30, 2011    8.30%   65,000        65,000
October 13, 1998 F Bonds    November 30, 2018 7.475% 285,000           ---
                                                   $ 626,816      $448,754

Principal   and   interest  payments  are  made   in   semi-annual
installments.  The Salton Sea Notes and Bonds are secured  by  the
Salton  Sea Project plants and the Zinc Recovery Project, as  well
as an assignment of the right to receive various royalties payable
to  Magma  in  connection with its Imperial Valley properties  and
distributions from the Partnership Project. The Salton  Sea  Notes
and Bonds are nonrecourse to the Company.  See Note 21.

On  October 13, 1998, the Funding Corporation completed a sale  to
institutional  investors of $285,000 aggregate  amount  of  7.475%
Senior  Secured  Series F Bonds due November 30, 2018,  which  are
nonrecourse to the Company. The proceeds from the offering will be
used to fund construction of the Zinc Recovery Project, Salton Sea
V,  the  CE  Turbo Project, the Region  2  Brine  Facilities
Construction, additional capital improvements and financing costs.

Pursuant   to   a   depository  agreement,   Funding   Corporation
established a debt service reserve fund in the form of a letter of
credit in the amount of $42,457 from which scheduled interest  and
principal payments can be made.

Northern Eurobonds

The Northern debt includes a debenture due in 1999, which bears  a
fixed  interest  rate of 12.661%.  The debt also  includes  bearer
bonds repayable in 2005 and 2020, bearing fixed interest rates  of
8.625% and 8.875%, respectively.

The balance at December 31, 1998 and 1997 consists of the
following:

                                            1998          1997
Debenture due 1999                      $   94,393      $  97,530
Bearer bonds due 2005                      166,286        165,236
Bearer bonds due 2020                      166,106        164,966
                                         $ 426,785      $ 427,732

CE Electric UK Funding Company Senior Notes and Sterling Bonds

On  December 15, 1997, CE Electric UK Funding Company, an indirect
subsidiary  of the Company (the "CE Electric UK Funding Company"),
issued  $125,000 of 6.853% senior notes due 2004, and $237,000  of
6.995%  senior notes due 2007 (collectively, the "CE  Electric  UK
Funding  Company  Senior Notes"), and  pounds 200,000 of  7.25%  Sterling
Bonds  due  2022. The CE Electric UK Funding Company Senior  Notes
<PAGE>
and   Sterling  Bonds  prohibit  distributions  to  any   of   its
shareholders  unless certain financial ratios are met  by  the  CE
Electric  UK  Funding Company or the long term debt  rating  falls
below a prescribed level.

On  December 15, 1997, CE Electric UK Funding Company entered into
certain  interest  rate swap agreements for  the  CE  Electric  UK
Funding   Company  Senior  Notes  with  two  large  multi-national
financial  institutions.  The swap agreements effectively  convert
the  U.S.  dollar fixed interest rate to a fixed rate in Sterling.
For  the  $125,000  of 6.853% Senior Notes, the agreements  extend
until December 30, 2004 and convert the U.S. dollar interest  rate
to  a  fixed Sterling rate of 7.744%. For the $237,000  of  6.995%
Senior  Notes, the agreements extend until December 30,  2007  and
convert the U.S. dollar interest rate to a fixed Sterling rate  of
7.737%.   The  estimated fair value of these  swap  agreements  is
approximately  $19,859 based on quotes from the counter  party  to
these  instruments and represents the estimated  amount  that  the
Company would expect to pay to terminate these agreements.  It  is
the  Company's  intention  to hold the swap  agreements  to  their
intended maturity.

Power Resources Project Financing Debt

Power  Resources, an indirect wholly-owned subsidiary, has project
financing  debt  with  a  consortium of banks  with  interest  and
principal due quarterly over a 15-year period, beginning March 31,
1989.  The original principal carried variable interest rate based
on  the London Interbank Offer Rate ("LIBOR") with a .85% interest
margin  through the 5th anniversary of the loan, a 1.00%  interest
margin  from  the 5th anniversary through the 12th anniversary  of
the  loan  and  a 1.25% interest margin from the 12th  anniversary
through the end of the loan.

Effective  June  5, 1989, PRI entered into an interest  rate  swap
agreement with the lender as a means of hedging floating  interest
rate  exposure  related  to  its  15-year  term  loan.   The  swap
agreement  was  for  initial  notional  amounts  of  $55,000   and
$110,000, declining in correspondence with the principal balances,
and  effectively  fixed the interest rates at 9.385%  and  9.625%,
respectively.   The estimated cost to terminate the interest  rate
swap  agreement,  based on termination values  obtained  from  the
lender,  was  $9,904 and $10,550 at December 31,  1998  and  1997,
respectively.  See Note 21.

Coso Funding Corp. Project Loans

The  Coso Funding Corp. project loans are from Coso Funding Corp.,
a  single-purpose corporation formed to issue notes  for  its  own
account  and  act as an agent on behalf of the Coso Project.   The
Coso  Funding Corp. project loans carry a fixed interest rate with
weighted average interest rates of 8.67% and 8.65% at December 31,
1998  and 1997, respectively.  The loans have scheduled repayments
through   December  2001.   The  Coso  Project   has   established
irrevocable letters of credit of $67,850 as a debt service reserve
fund.  See Note 21.

Casecnan Notes and Bonds

In  November 1995, the Company closed the financing and  commenced
construction  of the Casecnan Project, a combined  irrigation  and
150  net  MW hydroelectric power generation project (the "Casecnan
Project")  located in the central part of the island of  Luzon  in
the  Republic  of the Philippines.  CE Casecnan Water  and  Energy
Company,  Inc., a Philippine corporation ("CE Casecnan") which  is
expected  to  be at least 70% indirectly owned by the Company,  is
developing the Casecnan Project.

On  November  27, 1995, CE Casecnan issued $371,500 of  notes  and
bonds  to finance the construction of the Casecnan Project.  These
consist  of $75,000 Senior Secured Floating Rate Notes (FRNs)  due
2002; $125,000 Senior Secured Series A Notes (Series A Notes) with
interest at 11.45% due 2005; and $171,500 Senior Secured Series  B
Bonds   (Series  B  Bonds)  with  interest  at  11.95%  due  2010.
Quarterly interest payments for the FRNs commenced on February 15,
1996,  and  semiannual interest payments for Series  A  Notes  and
Series B Bonds commenced on May 15, 1996.

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

On  April 8, 1998, the Company converted the construction  project
financing for its Malitbog geothermal power project to term loans.
The  Overseas Private Investment Corporation ("OPIC") is providing
term  loan financing of $54,868 that was fixed as of June 15, 1998
at  an  interest  rate  of 9.176%.  A syndicate  of  international
commercial banks is providing term loan financing of $98,938 at  a
variable  interest  rate based on LIBOR  (7.47%  at  December  31,
1998).  The loans have scheduled repayments through June 2005.

Upper Mahiao Loans

On  May  5,  1998, the Company converted the construction  project
financing  for its Upper Mahiao geothermal power project  to  term
loans.  Export-Import Bank of the United States ("Ex-Im Bank")  is
providing term loan financing of $140,666 at a fixed interest rate
of  5.95%.   United  Coconut Planters Bank of the  Philippines  is
providing  term  loan financing of $9,444 at a  variable  interest
rate  based on LIBOR (8.25% at December 31, 1998).  The loans have
scheduled repayments through June 2006.

Mahanagdong Loans

On  June  18, 1998, the Company converted the construction project
financing  for  its Mahanagdong geothermal power project  to  term
loans.  Ex-Im Bank is providing term loan financing of $175,225 at
a  fixed rate of 6.92%.  OPIC is providing term loan financing  of
$38,857  that  was fixed as of September 30, 1998 at  an  interest
rate  of  7.6%.  The loans have scheduled repayments through  June
2007.

Northern Short Term Treasury Loan

Northern  had short term money market loans in place  at  December
31,   1998  of  $72,740.   The  amounts  have  varying  maturities
generally  less  than one month and carry variable interest  rates
based  on  LIBOR and ranging from 6.22% to 7.22% at  December  31,
1998.

CE Gas Loan

CE  Gas,  a  wholly  owned  subsidiary of Northern,  had  borrowed
$41,355  on a revolving facility at December 31, 1998 to fund  the
purchase  of certain UK gas assets in the North Sea.   The  amount
carries  a  variable  interest rate  based  on  LIBOR  (7.065%  at
December  31,  1998).   Total  unused capacity  of  the  revolving
facility at December 31, 1998 was $16,542.

Annual Repayments of Subsidiary and Project Debt

The   annual  repayments  of  the  subsidiary  and  project  debt,
excluding  construction loans, for the years beginning January  1,
1999 and thereafter are as follows:

<TABLE>
<CAPTION>
                                                                              Northern
                         CE Electric UK                                      Short Term
     Salton Sea          Funding Company           Coso  Casecnan Philippines Treasury Loan,
     Notes and Northern Senior Notes and Power   Funding Notes &     Term     CE Gas Loan
       Bonds  Eurobonds  Sterling Bonds Resources  Corp.  Bonds      Loans    and Other      Total
<S>  <C>       <C>         <C>           <C>      <C>      <C>      <C>      <C>          <C>   
1999 $ 57,836  $ 94,393    $     ---     $ 14,268 $ 31,717 $    --- $ 68,264 $  115,013   $  381,491
2000   25,072       ---          ---       16,087    4,080   18,750   68,264        ---      132,253
2001   23,658       ---          ---       18,119   31,908   29,625   68,264        ---      171,574
2002   28,572       ---          ---       20,312      ---   35,200   68,264        ---      152,348
2003   28,086       ---          ---       21,743      ---   41,467   72,152        ---      163,448
There
after 463,592   332,392      684,986          ---      ---  246,458  172,790        ---    1,900,218
     $626,816  $426,785     $684,986      $90,529  $67,705 $371,500 $517,998 $  115,013   $2,901,332
</TABLE>
<PAGE>
CE Indonesia Funding Corp. Construction Loans

In  June  1997, the Company's indirect special-purpose subsidiary,
CE  Indonesia  Funding  Corp., entered into a  $400,000  revolving
credit  facility (which is nonrecourse to the Company) to  finance
the development and construction of the Company's geothermal power
facilities  in  Indonesia.   At  December  31,  1998,  the  credit
facility  relating  to Dieng was $136,944 and carried  a  variable
interest rate (7.12% at December 31, 1998).

On  September 2, 1997, Patuha Power announced the funding  of  the
Patuha  Unit I project pursuant to the CE Indonesia Funding  Corp.
facility arranged in June 1997.  At December 31, 1998, the  credit
facility  relating  to Patuha was $55,534 and carried  a  variable
interest rate (7.12% at December 31, 1998).

9. Income Taxes

Provision  for  income taxes was comprised  of  the  following  at
December 31:
                                      1998      1997     1996

Currently payable:
State                             $   5,677 $  5,084  $ 7,520
Federal                              33,160   33,114   19,873
Foreign                              20,096    5,262    2,176
                                     58,933   43,460   29,569
Deferred:
State                                   161     (264)   1,619
Federal                              14,973   14,579    9,209
Foreign                              19,198   41,269    1,424
                                     34,332   55,584   12,252
Total                             $  93,265 $ 99,044  $41,821

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

                                                  1998         1997       1996
Federal statutory rate                           35.00%       35.00%    35.00%
Percentage depletion in excessof cost depletion  (3.52)       (3.77)    (6.12)
Investment and energy tax credits                 (.93)        (.64)    (8.34)
State taxes, net of federal tax effect            1.71         1.59      4.38
Goodwill amortization                             2.51         2.06      2.51
Dividends on convertible preferred 
  securities of subsidiary trusts*               (4.63)       (4.12)    (1.17)
Tax effect of foreign income                      1.86         2.64      2.54
Asset valuation impairment                         ---        15.47       ---
Other                                             2.28         2.08       .99
 Effective tax rate                              34.28%       50.31%    29.79%
 * Dividends on convertible preferred securities of subsidiary
trusts are included in minority interest.

Deferred tax liabilities (assets) are comprised of the following
at December 31:
                                                     1998           1997
Depreciation and amortization, net                  $  769,376   $  802,215
Pensions                                                22,305       19,441
Unremitted foreign earnings                             25,393       10,781
Other                                                      ---        3,324
<PAGE>
                                                       817,074      835,761

Deferred contract costs                               (182,745)    (193,996)
Deferred income                                         (9,458)     (12,690)
General business tax credits                           (21,300)     (42,049)
Alternative minimum tax credits                        (44,452)     (39,402)
Accruals not currently deductible for tax purposes     (11,591)     (31,561)
Other                                                   (4,137)      (7,004)
                                                      (273,683)    (326,702)

Net deferred taxes                                    $543,391     $509,059


The  Company  has unused low income housing and geothermal  energy
tax credit carryforwards of approximately $21,300 expiring between
2011  and  2018.  The  Company also has approximately  $44,452  of
alternative  minimum  tax  credit  carryforwards  which  have   no
expiration date.

10.     Company-Obligated   Mandatorily   Redeemable   Convertible
Preferred Securities of Subsidiary Trusts

The Company has organized special purpose Delaware business trusts
("Trust  I",  "Trust  II"  and "Trust III"  or  collectively,  the
"Trusts")  pursuant  to  their  respective  amended  and  restated
declarations  of  trusts (collectively, the  "Declarations").   On
April  12,  1996,  February  26, 1997 and  August  12,  1997,  the
Company,    through   these   Trusts,   issued   Company-obligated
mandatorily    redeemable   convertible    preferred    securities
(collectively, the "Trust Securities") as follows:

      Issuer                    Issue Date    Rate    Amount    Conversion Rate
CalEnergy Capital Trust I    April 12,1996    6.25%  $103,930        1.6728
CalEnergy Capital Trust II   February 26,1997 6.25%  $180,000        1.1655
CalEnergy Capital Trust III  August 12, 1997  6.50%  $270,000        1.047

The  Company owns all of the common securities of the Trusts.  The
Trust  Securities have a liquidation preference of  fifty  dollars
each  and  represent undivided beneficial ownership  interests  in
each of the Trusts. The assets of the Trusts consist solely of the
Company's Convertible Subordinated Debentures due March 10,  2016,
February  25,  2012  and  September  1,  2027,  respectively,   in
outstanding aggregate principal amounts of $103,930, $180,000  and
$270,000,  respectively  (collectively, the  "Junior  Debentures")
issued  pursuant to their respective indentures.   The  indentures
include  agreements by the Company to pay expenses and obligations
incurred  by the Trusts.  Each Trust Security with a par value  of
$50  is  convertible at the option of the holder at any time  into
shares   of   the  Company's Common Stock based on the  conversion
rate and subject to customary anti-dilution adjustments.

Until  converted  into  the  Company's  Common  Stock,  the  Trust
Securities will have no voting rights with respect to the  Company
and,  except  under certain limited circumstances,  will  have  no
voting  rights  with respect to the Trusts. Distributions  on  the
Trust  Securities  (and Junior Debentures) are cumulative,  accrue
from  the  date of initial issuance and are payable  quarterly  in
arrears.   The  Junior  Debentures are subordinated  in  right  of
payment  to all senior indebtedness of the Company and the  Junior
Debentures are subject to certain covenants, events of default and
optional and mandatory redemption provisions, all as described  in
the Junior Debenture indentures.

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
<PAGE>
Trust Securities.  Considered together, the undertakings contained
in  the Declarations, Junior Debentures, Indentures and Guarantees
constitute full and unconditional guarantees by the Company of the
Trusts' obligations under the Trust Securities.

11.Preferred Stock

The Company distributed a dividend of one preferred share purchase
right  ("right") for each outstanding share of common  stock.  The
rights are not exercisable until ten days after a person or  group
acquires or has the right to acquire, beneficial ownership of  20%
or  more  of the Company's common stock or announces a  tender  or
exchange offer for 30% or more of the Company's common stock. Each
right entitles the holder to purchase one one-hundredth of a share
of  Series  A  junior preferred stock for $52. The rights  may  be
redeemed  by the Board of Directors up to ten days after an  event
triggering  the distribution of certificates for the rights.   The
rights  will  expire, unless previously redeemed or exercised,  on
November 30, 1999. The rights are automatically attached  to,  and
trade with, each share of common stock.

12.Stock Options and Restricted Stock

The  Company has issued various stock options. As of December  31,
1998, a total of 1,075 shares are reserved for stock options,  and
5,710 shares have been granted and remain outstanding at prices of
$9.71 to $34.69 per share.

The  Company  has  stock  option plans  under  which  shares  were
reserved for grant as incentive or non-qualified stock options, as
determined  by the Board of Directors. The plans allow options  to
be  granted at 85% of their fair market value of the common  stock
at  the  date of grant. Generally, options are issued at  100%  of
fair  market  value  of the common stock at  the  date  of  grant.
Options  granted  under the 1996 Plan become  exercisable  over  a
period of two to five years and expire if not exercised within ten
years from the date of grant or, in some instances, a lesser term.

The Company granted 500 shares of restricted common stock with  an
aggregate   market   value  of  $9,500   in   exchange   for   the
relinquishment  of 500 stock options which were  canceled  by  the
Company.  The shares have all rights of a shareholder, subject  to
certain  restrictions on transferability and risk  of  forfeiture.
Unearned compensation equivalent to the market value of the shares
at  the date of issuance was charged to stockholders' equity. Such
unearned  compensation was amortized over the  vesting  period  of
which  125  shares were immediately vested and the  remaining  375
shares  vested  through January 1, 1998. Accordingly,  $5,471  and
$1,535  of  unearned  compensation  was  charged  to  general  and
administrative expense in 1997 and 1996, respectively.

Transactions in Stock Options

                                                    Options Outstanding
                     Shares Available
                      for Grant Under       Option Price Weighted Avg
                     1996 Option Plan Shares Per Share   Option Price Total
Balance December 31, 1995    261       9,291 $3.00-$19.00   $12.84    $119,332
     Options granted      (1,157)      1,157 25.06- 30.38    28.17      32,590
     Options terminated      468        (468) 3.00- 19.00    17.96      (8,406)
     Options exercised       ---      (5,203) 3.00- 21.68    11.13     (57,931)
     Additional shares 
 reserved under 1996 
 Option Plan                 739         ---          ---      ---         ---
Balance December 31,1996     311       4,777  3.00- 30.38    17.92      85,585
     Options granted      (2,307)      2,513 29.06- 40.81    34.80      87,457
     Options terminated      165        (165) 3.00- 29.06    20.04      (3,307)
     Options exercised       ---        (345) 3.74- 29.06    13.28      (4,583)
     Additional shares 
 reserved under 1996 
 Option Plan               2,000         ---          ---      ---         ---

Balance December 31,1997     169       6,780  3.74- 40.81    24.36     165,152
<PAGE>
     Revaluation             ---         --- 29.00- 40.81      ---     (16,011)
     Options granted        (405)        405 24.22- 28.75    24.61       9,968
     Options terminated      311      (1,311) 3.74- 25.06    14.71     (19,284)
     Options exercised       ---        (164) 3.74- 24.70    11.41      (1,872)
     Additional shares 
  reserved under 1996 
  Option Plan              1,000         ---          ---      ---         ---
Balance December 31,1998   1,075       5,710 $9.71- $34.69  $24.16    $137,953
     Options exercisable at:
      December 31, 1996                3,071 $3.00- $30.38  $14.25     $43,770
      December 31, 1997                3,665 $3.74- $40.19  $18.12     $66,425
      December 31, 1998                3,167 $9.71- $34.56  $20.55     $65,097

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

   The following table summarizes information about stock options
outstanding and exercisable as of December 31, 1998:

                           Options Outstanding  Options Exercisable
                                Weighted         Weighted              Weighted
  Range of          Number      Average     Average Remaining  Number    Average
Exercise Prices Outstanding Exercise Price Contractual Life Exercisable Exercise
                                                                         Price
$ 9.71 $18.99      1,610      $   16.07       5 years         1,573   $   16.07
 19.00  24.99      1,378          22.98       7 years           682       21.86
 25.00  28.99        818          28.34       9 years           278       28.08
 29.00  34.69      1,904          30.06       8 years           634       29.29
                   5,710      $   24.16       7 years         3,167   $   20.55

The Company applies the intrinsic value based method of accounting
for its stock-based employee compensation plans. If the fair value
based  method had been applied, non-cash compensation expense  and
the  effect  on  net income available to common  stockholders  and
earnings per share would have been approximately $4,811, or  $0.03
per  share for 1998 and $3,600, or $0.05 per share for  1997.   If
the  fair  value based method had been applied for 1996,  non-cash
compensation  expense and the effect on net  income  available  to
common  stockholders  and  earnings  per  share  would  have  been
immaterial.  The fair value for stock options was estimated  using
the  Black-Scholes option pricing model with assumptions  for  the
risk-free  interest rate of 5.10% in 1998 and 5.50%  in  1997  and
6.00% in 1996, expected volatility of 35% in 1998 and 25% in  1997
and  22% in 1996, expected life of approximately 3.4 years in 1998
and  3.7  years  in 1997 and 4.5 years in 1996,  and  no  expected
dividends.   The  weighted average fair value of  options  granted
during  1998, 1997 and 1996 was $7.71, $9.55 and $8.62 per option,
respectively.

13.               Equity Offering

On  October 17, 1997, the Company completed the public offering of
17,100 shares of its common stock ("Common Stock") at $37 7/8  per
share  (the  "Public  Offering").  In addition,  2,000  shares  of
Common Stock were purchased from the Company in a direct sale by a
trust affiliated with the Chairman and Chief Executive Officer  of
PKS (the "Direct Sale"), contemporaneously with the closing of the
Public  Offering.   Proceeds from the  Public  Offering   and  the
Direct Sale were approximately $699,920.

14.    Asset Valuation Impairment Charge

The  non-recurring charge of $87,000 represents an asset valuation
impairment  charge  under  SFAS  No.  121,  "Accounting  for   the
Impairment of Long-Lived Assets," relating to the Company's assets
in  Indonesia.  The Company intends to continue to take actions to
require  the  Government  of Indonesia to  honor  its  contractual
obligations;  however,  the  ultimate  outcome  of   the   current
<PAGE>
arbitration  in  Indonesia with respect to the abrogation  by  the
Indonesian government of the Dieng, Patuha and Bali contracts  and
sovereign  guarantees creates significant risk to these  projects.
Consequently, the charge of $87,000 represents the amount by which
the  carrying amount of such assets exceed the fair value  of  the
assets  determined  by discounting the expected  future  net  cash
flows  of the Indonesia projects, assuming proceeds from political
risk insurance and no tax benefits.

15.            Extraordinary Item

On July 31, 1997, the Finance Act in the United Kingdom was passed
by  Parliament  and included the introduction of a  one  time  so-
called  "windfall tax" equal to 23% of the difference between  the
price   paid  for  Northern  upon  privatization  and  the  Labour
government's  assessed  "value"  of  Northern  as  calculated   by
reference to a formula set forth in the July budget. This amounted
to  $135,850,  net  of  minority interest of  $58,222,  which  was
recorded as an extraordinary item.  The first installment was paid
December 1, 1997 and the remainder was paid in 1998.

16.Fair Value of Financial Instruments

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

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

Debt  instruments  - The fair value of all debt issues  listed  on
exchanges  has  been estimated based on the quoted market  prices.
The  Company is unable to estimate a fair value for the Philippine
loans  as there are no quoted market prices available.  Given  the
current uncertainty in Indonesia described in Note 19, the Company
is  unable  to estimate a fair value for the CE Indonesia  Funding
Corp. construction loans.

Other financial instruments - All other financial instruments of a
material  nature fall into the definition of short-term  and  fair
value is estimated as the carrying amount.

The  carrying  amounts in the table below are included  under  the
indicated captions in Notes 7, 8 and 10.


                                         1998             1997
                                       Estimated        Estimated
                          Carrying       Fair   Carrying  Fair
                           Value        Value     Value   Value
Senior Discount Notes     $369,501    $388,438 $529,640 $569,148
9.5% Senior Notes          224,265     243,328  224,205  243,615
7.63% Senior Notes         350,000     372,365  350,000  352,857
Limited Recourse Senior 
 Secured Notes             200,000     217,900  200,000  217,829
$1.4 Billion Senior Notes1,400,000   1,495,742      ---      ---
$100 Million Senior Notes  102,225     111,973      ---      ---
Salton Sea Notes and Bonds 626,816     646,397  448,754  463,720
Northern Eurobonds         426,785     516,080  427,732  482,064
CE Electric UK Funding 
 Company Senior Notes      360,070     381,701  357,331  357,331
CE Electric UK Funding 
 Company Sterling Bonds    324,916     391,199  322,534  333,257
Power Resources 
 Project Debt               90,529      90,529  103,334  103,334
Coso Funding Corp. Project 
 Loans                      67,705      71,128  106,616  112,932
Casecnan Notes and Bonds   371,500     302,248      ---      ---
Northern Short Term 
 Treasury Loan              72,740      72,740      ---      ---
CE Gas Loan                 41,355      41,355      ---      ---
<PAGE>
Other                          918         918    5,962    5,962
Convertible Preferred 
 Securities of Subsidiary 
 Trusts                    553,930     562,012  553,930  514,373

17.  Regulatory Matters

Northern  is  subject  to  price cap  regulation.   Price  control
formulas  for the supply and distribution businesses are  enforced
by the Office of Electricity Regulation ("OFFER").

In the distribution business the current price control is expected
to  last  until 2000.  The formula was reviewed with  effect  from
April  1,  1995  and  April  1, 1996 which  resulted  in  one-time
reductions in allowed income per unit distributed of about 17% and
13%  respectively, with continuing real reductions in each of  the
subsequent  three years 1997/98 to 1999/2000. The current  formula
requires that each year regulated distribution income per unit  is
increased or decreased by RPI-Xd where RPI reflects the average of
the twelve month inflation rates recorded for the previous July to
December  period  and  Xd is set at 3%.  The  formula  also  takes
account of the changes in system electrical losses, the number  of
customers connected and the voltage at which customers receive the
units of electricity distributed.

In  the  supply  business  the current  formula  applies  only  to
domestic  and some smaller non-domestic customers in the Northeast
of  England.  The current formula took effect on April 1, 1998 and
requires Northern to reduce prices to those customers protected by
the  new price control from the level prevailing at August 1, 1997
by about 4.2% (minus inflation) with effect from April 1, 1998 and
by a further 3% (minus inflation) with effect from April 1, 1999.

The market for electricity supplied to customers with demands over
1MW  was  opened to competition in 1990.  In 1994 this  limit  was
reduced  to  0.1MW.   During 1998, liberalization  of  the  entire
market  commenced  in stages.  Complete liberalization  is  to  be
achieved by the summer of  1999.


18.  Pension Commitments

Northern  participates in the Electricity Supply  Pension  Scheme,
which  provides pension and other related defined benefits,  based
on   final   pensionable  pay,  to  substantially  all   employees
throughout the Electricity Supply Industry in the United Kingdom.

The  actuarial computation for December 31, 1998 and 1997  assumed
interest rates of 5.5% and 6.75%, respectively, an expected return
on  plan  assets  of  6.0%  and 7.25%,  respectively,  and  annual
compensation increases of 3.5% and 4.75%, respectively,  over  the
remaining  service  lives  of employees covered  under  the  plan.
Amounts funded to the pension are primarily invested in equity and
fixed income securities. Northern's funding policy for the plan is
to  contribute  annually at a rate that is intended  to  remain  a
level percentage of compensation for the covered employees.

The  following  table  details the funded status  and  the  amount
recognized in the balance sheet of the Company as of  December 31,
1998 and 1997.

                                                    1998         1997

Change in benefit obligation:
Benefit obligation at beginning of the year    $   888,500$   830,900
Service cost                                        12,600     12,600
Interest cost                                       58,800     62,400
Plan participants' contributions                     5,800      6,100
Benefits paid                                      (46,700)   (48,600)
Experience loss and change of assumptions            7,000     25,100
Benefit obligation at end of the year              926,000    888,500
<PAGE>
Change in plan assets:
Fair value of plan assets at beginning of 
  the year                                       1,012,600    881,700
Actual return on plan assets                       154,200    157,800
Contributions                                       23,000     21,700
Benefits paid                                      (46,700)   (48,600)
Fair value of plan assets at end of the year     1,143,100  1,012,600

Funded status                                      217,100    124,100
Unrecognized net gain                              140,200     61,400
Prepaid benefit cost                          $     76,900 $   62,700

Net periodic pension cost for 1998 and 1997 included the following
components  (the  components for the period from  the  acquisition
date of Northern to December 31, 1996 are not meaningful):

                                                     1998       1997
Service cost - benefits earned during the period$   12,600  $  12,600
Interest cost on projected benefit obligation       58,800     62,400
Actual return on plan assets                       (68,000)   (71,400)
Net periodic pension cost                       $    3,400 $    3,600

19.                          Commitments and Contingencies

Indonesia

On  December  2,  1994,   subsidiaries of  the  Company,  Himpurna
California  Energy  Ltd. ("HCE") and Patuha  Power,  Ltd.  ("PPL",
together   with  HCE,  the  "Indonesian  Subsidiaries")   executed
separate  joint  operation contracts for the  development  of  the
geothermal steam field and geothermal power facilities located  in
Central Java in Indonesia with Perusahaan Pertambangan Minyak  Dan
Gas   Bumi  Negara  ("Pertamina"),  the  Indonesian  national  oil
company,   and   executed  separate  "take-or-pay"  energy   sales
contracts with both Pertamina and P.T. PLN (Persero) ("PLN"),  the
Indonesian national electric utility. The Government of  Indonesia
provided sovereign guarantees of the obligations under the  "take-
or-pay" contracts.

In  1997  and  1998 a series of Indonesian government decrees  and
other  actions (including the non-payment of all monthly  invoices
from  HCE's Dieng Unit I, which became operational in March  1998)
have  created significant uncertainty as to whether  PLN  and  the
Indonesian government will honor their contractual obligations  to
the Indonesian Subsidiaries.   The Indonesian Subsidiaries in 1998
initiated  dispute  resolution  procedures  under  the  ESCs   and
sovereign guarantees with PLN and the Government of Indonesia  and
subsequently commenced arbitration to resolve the dispute and they
intend  to  continue to take actions to require the Government  of
Indonesia to honor its contractual obligations.  However,  actions
by  the Government of Indonesia have created significant risks  to
the  Indonesian Subsidiaries.  Dieng Unit I was operationally  and
contractually  completed  in  March 1998  when  the  "take-or-pay"
obligations  under its contract with PLN commenced.  However,  PLN
has   defaulted  on  the  contractually  required  and   sovereign
guaranteed  "take-or-pay" payment obligations.   Accordingly,  the
arbitration  is  proceeding  before an  international  arbitration
panel,  as  provided under the Indonesian Subsidiaries'  contracts
with PLN.  The arbitration involves both PLN and the Government of
Indonesia  and  is  expected to conclude in the third  quarter  of
1999.

NYSEG

On  February 14, 1995, NYSEG filed with the FERC a Petition for  a
Declaratory  Order,  Complaint, and Request  for  Modification  of
Rates  in Power Purchase Agreements Imposed Pursuant to the Public
Utility Regulatory Policies Act of 1978 ("Petition") seeking  FERC
(i)  to  declare that the rates NYSEG pays under the Saranac  PPA,
<PAGE>
which was approved by the New York Public Service Commission  (the
"PSC") were in excess of the level permitted under PURPA and  (ii)
to  authorize  the PSC to reform the Saranac PPA.   On  March  14,
1995,  the  Saranac  Partnership intervened in opposition  to  the
Petition  asserting,  inter  alia,  that  the  Saranac  PPA  fully
complied with PURPA, that NYSEG's action was untimely and that the
FERC  lacked  authority to modify the Saranac PPA.  On  March  15,
1995,  the  Company intervened also in opposition to the  Petition
and asserted similar arguments.  On April 12, 1995, the FERC by  a
unanimous (5-0) decision issued an order denying the various forms
of  relief requested by NYSEG and finding that the rates  required
under  the Saranac PPA were consistent with PURPA and the   FERC's
regulations.   On May 11, 1995, NYSEG requested rehearing  of  the
order and, by order issued July 19, 1995, the FERC unanimously (5-
0) denied NYSEG's request.  On June 14, 1995, NYSEG petitioned the
United  States  Court  of  Appeals for the  District  of  Columbia
Circuit  (the "Court of Appeals") for review of FERC's  April  12,
1995  order. FERC moved to dismiss NYSEG's petition for review  on
July  28,  1995.   On  October 30, 1996, all parties  filed  final
briefs  and the Court of Appeals heard oral arguments on  December
2, 1996.  On July 11, 1997, the Court of Appeals dismissed NYSEG's
appeal  from  FERC's  denial  of the  petition  on  jurisdictional
grounds.

On  August  7, 1997, NYSEG filed a complaint in the U.S.  District
Court for the Northern District of New York against the FERC,  the
PSC  (and  the Chairman, Deputy Chairman and the Commissioners  of
the  PSC  as individuals in their official capacity), the  Saranac
Partnership  and  Lockport  Energy Associates,  L.P.  ("Lockport")
concerning  the power purchase agreements that NYSEG entered  into
with Saranac Partners and Lockport.

NYSEG's  suit  asserts  that  the  PSC  and  the  FERC  improperly
implemented PURPA in authorizing the pricing terms that NYSEG, the
Saranac  Partnership  and Lockport agreed to in  those  contracts.
The action raises similar legal arguments to those rejected by the
FERC  in  its April and July 1995 orders.  NYSEG in addition  asks
for  retroactive reformation of the contracts as of  the  date  of
commercial operation and seeks a refund of $281 million  from  the
Saranac Partnership.  Saranac and other parties have filed motions
to dismiss and oral arguments on those motions were heard on March
2, 1998 and again on March 3, 1999.  Saranac believes that NYSEG's
claims  are  without merit for the same reasons described  in  the
FERC's orders.

20.  Segment Information

The  Company has adopted SFAS No. 131 "Disclosures about  Segments
of  an  Enterprise and Related Information" which requires certain
disclosures  about  operating  segments  in  a  manner   that   is
consistent  with how management evaluates the performance  of  the
segment.   The  Company has identified three  reportable  business
segments  principally based on geographic area, pursuant  to  SFAS
131:    Domestic   electricity  generation,  foreign   electricity
generation  (principally  the  Philippines)  and  foreign  utility
operations.   Information  related  to  the  Company's  reportable
operating segments is shown below.

                             1998      1997       1996
Revenue
Domestic generation      $  583,311$  570,587$  486,189
Foreign generation          223,650   102,960    33,282
Foreign utility           1,842,930 1,566,442    39,191
Segment revenue           2,649,891 2,239,989   558,662
Corporate                    32,820    30,922    17,533
                         $2,682,711$2,270,911 $ 576,195
Operating income *
Domestic generation       $ 313,983 $ 301,589 $ 259,665
Foreign generation          142,977    61,131    16,766
Foreign utility             172,772   191,299     6,163
Segment operating income    629,732   554,019   282,594
Corporate                   (10,387)  (12,882)  (10,931)
                          $ 619,345 $ 541,137 $ 271,663
<PAGE>
Capital expenditures
Domestic generation      $  105,458 $  58,956 $  85,764
Foreign generation          204,301   177,813   248,228
Foreign utility             184,631   134,050       ---
Segment capital expenditures494,390   370,819   333,992
Corporate                       537     9,830     7,714
                          $ 494,927  $380,649 $ 341,706
* Operating income excludes the loss on equity investment in
Casecnan, net interest expense and the non-recurring Indonesian
asset impairment charge.

                             1998          1997
Identifiable assets
Domestic generation       $ 2,458,842  $ 2,268,629
Foreign generation          1,956,387      835,616
Foreign utility             3,095,839    2,937,686
Segment identifiable assets 7,511,068    6,041,931
Corporate                   1,592,456    1,445,695
                          $ 9,103,524  $ 7,487,626
Long-lived assets
Domestic generation       $ 1,960,433  $ 1,966,499
Foreign generation          1,275,104      524,937
Foreign utility             2,519,615    2,331,533
Segment long-lived assets   5,755,152    4,822,969
Corporate                      19,063       18,729
                          $ 5,774,215  $ 4,841,698

The remaining differences from the segment amounts to the
consolidated amounts relate principally to the corporate functions
including administrative costs, corporate cash and related
interest income.

21.  Subsequent Events

As  discussed  in Note 3, on August 11, 1998, the Company  entered
into  an  Agreement  and  Plan of Merger  with  MidAmerican.   The
MidAmerican  Merger closed on March 12, 1999 and the Company  paid
$27.15  in  cash for each outstanding share of MidAmerican  common
stock  for  a  total of approximately $2.42 billion in  a  merger,
pursuant  to  which  MidAmerican became an indirect  wholly  owned
subsidiary   of   the   Company.    Additionally,   the    Company
reincorporated  in  the  State of Iowa,  was  renamed  MidAmerican
Energy  Holdings Company and upon closing became an exempt  public
utility holding company.

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

On January 29, 1999, the Company commenced a cash offer for all of
its  outstanding  Limited Recourse Notes.   The  Company  received
tenders  from holders of an aggregate of $195,765 principal  which
were paid on March 3, 1999, at a redemption price of 110.025% plus
accrued interest.

On  February  8,  1999, the Company created a new  subsidiary,  CE
Generation LLC ("CE Generation") and subsequently transferred  its
interest  in the Company's power generation assets in the Imperial
Valley and the Gas Plants to CE Generation.
<PAGE>
On  February 26, 1999, the Company closed the sale of all  of  its
indirect  ownership  interests  in  the  Coso  Joint  Ventures  to
Caithness  Energy LLC.  The price includes $205,000  in  cash  and
$5,000 in contingent payments.

On  March  2,  1999,  CE Generation closed the  sale  of  $400,000
aggregate principal amount of its 7.416% Senior Secured Bonds  due
2018 and distributed the proceeds to the Company.

On  March  3,  1999, the Company closed the sale  of  50%  of  its
ownership  interests in CE Generation to an affiliate of  El  Paso
Energy  Corporation for approximately $247,000 in cash, $6,500  in
contingent payments and $23,500 in equity commitments.   Including
the  gross  proceeds  from the CE Generation  debt  offering,  the
aggregate consideration was approximately $677,000.

On  March  11,  1999,  MidAmerican Funding,  LLC,  a  wholly-owned
subsidiary of the Company, issued $200,000 of 5.85% Senior Secured
Notes  due 2001, $175,000 of 6.339% Senior Secured Notes due 2009,
and  $325,000  of  6.927%  Senior Secured  Bonds  due  2029.   The
proceeds  from the offering were used to complete the  MidAmerican
Merger.

<PAGE>
22. QUARTERLY FINANCIAL DATA (UNAUDITED)

Following is a summary of the Company's quarterly results of
operations for the years ended December 31, 1998 and 1997.

                                         Three Months Ended *
 1998:                         March 31    June 30    September 30 December 31
Operating revenue              $621,851   $590,589    $600,862        $741,904
Total revenue                   644,311    620,518     627,747         790,135
Total costs and expenses        588,401    555,961     537,477         728,819
Income before income taxes       55,910     64,557      90,270          61,316
Provision for income taxes       18,531     21,952      32,112          20,670
Income before minority interest  37,379     42,605      58,158          40,646
Minority interest                10,084     10,139      10,535          10,518
Income before extraordinary item 
  and cumulative effect of 
  change in accounting principle 27,295     32,466      47,623          30,128
Extraordinary item, net of tax      ---        ---         ---          (7,146)
Cumulative effect of change in
  accounting principle, net of tax  ---        ---         ---          (3,363)
Net income attributable to
  common  stockholders          $27,295    $32,466     $47,623         $19,619
Income per share before 
  extraordinary item and 
  cumulative effect of change
  in accounting principle      $    .45  $     .54   $     .80        $    .51
Extraordinary item                  ---        ---         ---            (.12)
Cumulative effect of change in
  accounting principle              ---        ---         ---            (.06)
Net income per share           $    .45  $     .54   $     .80      $      .33
Weighted average basic shares
  outstanding                    61,081     60,235      59,674          59,566
Income per share before extraordinary item
   and cumulative effect of change in
   accounting principal - 
   diluted                     $    .43   $    .51   $     .72       $     .48
Extraordinary item - diluted        ---        ---         ---            (.10)
Cumulative effect of change in
  accounting principle - diluted    ---        ---         ---            (.04)
Net income per share - diluted   $  .43   $    .51   $     .72      $      .34
Weighted average diluted shares
   outstanding                   69,343     74,346      73,540          73,627
<PAGE>
                                       Three Months Ended *
  1997:                      March 31   June 30  September 30   December 31
Operating revenue           $542,589   $505,922    $527,896      $589,931
  Total revenue              565,976    524,994     551,893       628,048
  Total costs and expenses   506,104    460,184     467,900       639,863
  Income (loss) before
   income taxes               59,872     64,810      83,993       (11,815)
  Provision for income taxes  22,249     24,342      27,929        24,524
  Income (loss) before        
   minority interest          37,623     40,468      56,064       (36,339)
  Minority interest           10,175      9,579       9,656        16,583
  Income (loss) before
   extraordinary item         27,448     30,889      46,408       (52,922)
  Extraordinary item             ---        ---    (135,850)          ---
  Net income (loss)                                               
 attributable to 
  common stockholders       $ 27,448    $30,889   $ (89,442)     $(52,922)
  Income (loss) per share before         
    extraordinary item      $    .43    $   .49   $     .73      $   (.67)
  Extraordinary item             ---        ---       (2.14)          ---
  Net income (loss) per         
 share                      $    .43    $   .49   $   (1.41)     $   (.67)
 Weighted average basic                                           
 shares outstanding           63,511     63,531      63,380        78,649
 Income (loss) per share
 before extraordinary item -
 diluted                    $    .42    $   .46   $     .67      $   (.67)
 Extraordinary item-diluted      ---        ---       (1.80)          ---
 Net income (loss) per
 share - diluted            $    .42    $   .46   $   (1.13)     $   (.67)
 Weighted average diluted                                                 
 shares outstanding           69,846     72,759      75,555        78,649
    

* The Company's operations are seasonal in nature.
<PAGE>


INDEPENDENT AUDITORS' REPORT

Board of Directors and Shareholders
MidAmerican Energy Holdings Company
Omaha, Nebraska

We  have  audited the accompanying consolidated balance sheets  of
MidAmerican  Energy Holdings Company (the successor  to  CalEnergy
Company, Inc.) and subsidiaries as of December 31, 1998 and  1997,
and   the   related   consolidated   statements   of   operations,
stockholders' equity and cash flows for each of the three years
in  the period ended December 31, 1998. These financial statements
are   the   responsibility  of  the  Company's   management.   Our
responsibility  is  to  express  an  opinion  on  these  financial
statements based on our audits.

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

In  our  opinion,  such consolidated financial statements  present
fairly,  in  all  material  respects, the  financial  position  of
MidAmerican  Energy Holdings Company and subsidiaries at  December
31,  1998  and 1997 and the results of their operations and  their
cash  flows  for  each  of the three years  in  the  period  ended
December   31,   1998,  in  conformity  with  generally   accepted
accounting principles.



Deloitte & Touche LLP
Omaha, Nebraska
January 28, 1999 (March 12, 1999 as to Note 3 and Note 21)