SECURITIES AND EXCHANGE COMMISSION

                    WASHINGTON, D.C.  20549

                           FORM 10-K

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

          For the fiscal year ended December 31, 1996
                   Commission File No. 1-9874

                    CALENERGY COMPANY, INC.
     (Exact name of registrant as specified in its charter)

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

   302 S. 36th Street, Suite 400, Omaha, NE              68131
(Address of principal executive offices)              (Zip Code)

Registrant's telephone number, including area code:  (402) 341-4500

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

                                            Name of exchange
Title of each class                         on which registered
Common Stock, $0.0675                       New York Stock Exchange
par value ("Common Stock")                  Pacific Stock Exchange
                                            London Stock Exchange

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

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

               Yes    X            No

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

     Based on the closing sales price of Common Stock on the New
York Stock Exchange on March 17, 1997 the aggregate market value
of  the  Common Stock held by non-affiliates of the Company  was
$2,223,535,825.

63,529,595 shares of Common Stock were outstanding on March 17, 1997.

                                
DOCUMENTS INCORPORATED BY REFERENCE

Incorporated  by reference into this Form 10-K,  in  response  to
Item  3 Part I, Items 6 through 8 of Part II and Items 10 through
13  of  Part  III, are the portions indicated herein of  (i)  the
annual  report  of  CalEnergy Company, Inc.  (the  "Company")  to
security holders for the fiscal year ended December 31, 1996 (the
"Annual Report"), and (ii) the Company's proxy statement dated on
or  about April 4, 1997 for the annual meeting of stockholders to
be held on May 15, 1997 (the "Proxy Statement").


                        TABLE OF CONTENTS

PART 1                                                         1
ITEM 1 BUSINESS                                                1
 GENERAL                                                       1
 THE FALCON SEABOARD ACQUISITION                               2
 THE NORTHERN ACQUISITION                                      2
 THE GLOBAL POWER GENERATION MARKET                            3
 THE ELECTRIC UTILITY INDUSTRY IN THE UNITED KINGDOM           4
 GEOTHERMAL ENERGY                                             5
 STRATEGY                                                      6
 THE COMPANY'S GENERATION PROJECT PORTFOLIO                    8
   INTERNATIONAL POWER GENERATION PROJECT PORTFOLIO            9
   DOMESTIC POWER GENERATION PROJECTS                          9
 INTERNATIONAL POWER GENERATION PROJECTS                      10
   PROJECTS IN OPERATION OR CONSTRUCTION                      10
     THE PHILIPPINES                                          10
     UPPER MAHIAO                                             11
     MAHANAGDONG                                              12
     MALITBOG                                                 13
     CASECNAN                                                 15
     INDONESIA                                                16
     DIENG UNIT I                                             17
     UNITED KINGDOM                                           18
     TEESSIDE                                                 18
     VIKING                                                   18
   PROJECTS IN DEVELOPMENT                                    18
     PHILIPPINES                                              19
     ALTO PEAK                                                20
     INDONESIA                                                20
     DIENG                                                    20
     PATUHA                                                   20
     BALI                                                     20
 INTERNATIONAL ELECTRICITY DISTRIBUTION AND SUPPLY OPERATIONS 20
   DISTRIBUTION OF ELECTRICITY                                21
   SUPPLY OF ELECTRICITY                                      23
   REGULATION UNDER THE ELECTRICITY ACT 1989                  25
 OTHER INTERNATIONAL BUSINESSES                               27
   NORTHERN UTILITY SERVICES LIMITED.                         27
   NORTHERN ELECTRIC RETAIL LIMITED.                          28
   NORTHERN METERING SERVICES LIMITED.                        28
   SOVEREIGN EXPLORATION LIMITED                              28
 DOMESTIC POWER GENERATION PROJECTS                           28
   PROJECTS IN OPERATION                                      28
     THE COSO PROJECT                                         28
     NAVY I                                                   29
     BLM                                                      29
     NAVY II                                                  29
     IMPERIAL VALLEY PROJECT                                  29
     VULCAN                                                   29
     HOCH (DEL RANCH)                                         30
     ELMORE                                                   30
     LEATHERS                                                 30
     SALTON SEA I PROJECT                                     30
     SALTON SEA II PROJECT                                    30
     SALTON SEA III PROJECT                                   30
     SALTON SEA IV PROJECT                                    31
     ROOSEVELT HOT SPRINGS                                    31
     DESERT PEAK                                              31
     ROYALTY INTEREST IN THE MAMMOTH PLANTS                   31
     ROYALTY INTEREST IN THE EAST MESA PLANT                  31
     YUMA                                                     31
     SARANAC                                                  32
     POWER RESOURCES                                          32
     NORCON                                                   33
   PROJECTS IN DEVELOPMENT                                    33
     SALTON SEA MINERALS EXTRACTION                           33
     GLASS MOUNTAIN                                           34
     THE BRPU PROCESS                                         34
 REGULATORY, ENERGY AND ENVIRONMENTAL MATTERS                 34
   UNITED STATES                                              34
   UNITED KINGDOM                                             35
 EMPLOYEES                                                    36
ITEM 2. PROPERTIES                                            36
ITEM 3. LEGAL PROCEEDINGS                                     37
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.  37
PART II                                                       38
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER'S MATTERS                                         38
ITEM 6. SELECTED FINANCIAL DATA                               39
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATION                            39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA           39
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE                           39
PART III                                                      40
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT   40
ITEM 11. EXECUTIVE COMPENSATION                               42
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT                                                    42
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS       42
PART IV                                                       43
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K                                           43
SIGNATURES                                                    45
EXHIBIT INDEX                                                 48


                             PART 1

Item 1    BUSINESS

General

      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.  The
Company  was  founded in 1971 and, through its  subsidiaries,  is
primarily engaged in the development, ownership and operation  of
environmentally   responsible   independent   power    production
facilities worldwide utilizing geothermal resources, natural  gas
and  hydroelectric or other energy sources, such as oil and coal.
In  addition, through its recently acquired subsidiary,  Northern
Electric  plc  ("Northern"),  the  Company  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.

      In  the  last two years, the Company has consummated  three
significant acquisitions, in addition to the recent approximately
$1.3  billion  acquisition  of  Northern  (described  below).  In
January 1995, the Company acquired Magma Power Company ("Magma"),
a  publicly-traded United States independent power producer  with
228  megawatts ("MW") of aggregate net operating capacity and 154
MW  of  aggregate net ownership capacity, for approximately  $958
million.  The  Magma  acquisition, combined  with  the  Company's
previously   existing  assets,  made  the  Company  the   largest
independent  geothermal power producer in the world today  (based
on  the Company's estimate of aggregate MW of electric generating
capacity in operation and under construction). In April 1996, the
Company  completed the buy-out for approximately $70  million  of
its  partner's  interests in four electric generating  plants  in
Southern  California, resulting in sole ownership of the Imperial
Valley  Projects' 228 MW of aggregate net operating capacity.  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  cogeneration facilities located in New York, Texas  and
Pennsylvania and a related gas transmission pipeline.

      Through  its subsidiaries and joint ventures,  the  Company
presently operates 19 projects with an aggregate net capacity  of
1,326 MW, in which it has a net ownership interest of 1,107 MW of
electric  generating  capacity. This includes  an  aggregate  net
ownership interest of 916 MW in facilities located in the  United
States (which facilities have an aggregate net capacity of  1,135
MW,  of  which 570 MW are fueled with natural gas and 565 MW  are
geothermal). The remaining 191 MW are supplied by two  geothermal
power production facilities owned and operated by the Company  in
the  Philippines.  These numbers do not reflect  47  small  scale
combined  heat  and  power facilities and a  diesel  fired  power
production facility in England (in which the Company has a  3  MW
net  ownership  interest)  that an indirect  Northern  subsidiary
operates.  Finally, the Company owns, but does not  operate,  202
net MW from the 1,875 MW Teesside Project in England.

      With respect to power generation projects that are financed
and   under  construction,  the  Company  has  an  aggregate  net
ownership  interest of 270 MW of electric generating capacity  in
two  geothermal power projects and one hydroelectric  project  in
the   Philippines,  which  collectively  have  an  aggregate  net
capacity of 459 MW. The Company is also currently constructing  a
55  net  MW geothermal project in Indonesia, in which the Company
has  an  aggregate net ownership interest of 26  MW  of  electric
generating capacity, as the first phase of the Company's  planned
Indonesian geothermal project development of approximately  1,000
MW under contract. The Company has commenced construction of a 50
MW  gas  fired power project in England in which the Company  has
net ownership interest of 18 MW. The Company expects that it will
operate all of these projects.

      The  Company  is also currently developing  six  additional
projects  with executed or awarded power sales contracts  in  the
Philippines,  Indonesia  and the United States.  The  Company  is
expected to have an approximate net ownership interest of 573  MW
in  these development projects (which represent an aggregate  net
capacity  of 1,260 MW of additional potential electric generating
capacity).  Substantial  contingencies  exist  with  respect   to
development projects, including, without limitation, the need  to
obtain  financing,  permits  and licenses  and  the  satisfactory
completion  of  construction. The Company expects  that  it  will
operate all of these projects.

      The  Company's  Common Stock is traded  on  the  New  York,
Pacific and London Stock Exchanges. As of the record date for the
annual  meeting  of  stockholders, March 17, 1996,  Peter  Kiewit
Sons'  Inc.  ('PKS")  was an approximate 32% stockholder  of  the
Company (on a fully diluted basis). PKS is a large employee-owned
construction,   mining   and  telecommunications   company   with
approximately $3 billion in revenues in 1996. PKS is one  of  the
largest  construction companies in North America and has been  in
the construction business since 1884.

      The  principal executive offices of the Company are located
at  302  South 36th Street, Suite 400, Omaha, Nebraska 68131  and
its   telephone  number  is  (402)  341-4500.   The  Company  was
incorporated in 1971 under the laws of the State of Delaware.

The Falcon Seaboard Acquisition

      On August 7, 1996 the Company completed the acquisition  of
Falcon  Seaboard,  including  its  ownership  interest  in  three
operating  gas-fired  cogeneration plants located  in  New  York,
Texas  and Pennsylvania and a related natural gas pipeline,  also
located  in New York, for a cash purchase price of $226  million.
The  three  cogeneration facilities, which are  described  below,
total  520  MW  in capacity and sell power under long-term  power
purchase agreements.

The Northern Acquisition

      On  December  24, 1996, CE Electric UK plc ("CE  Electric),
which  is  70%  owned  indirectly by the Company  and  30%  owned
indirectly by PKS, acquired majority ownership of the outstanding
ordinary  share  capital of Northern pursuant to a  tender  offer
(the  "Tender Offer"). The total amount expected to be  paid  for
all of Northern's ordinary and preference shares is approximately
$1.3  billion. In January 1997, CE Electric appointed a  majority
of  Northern's board of directors and assumed management control.
Through January 31, 1997, CE Electric had purchased more than 90%
of  Northern's  ordinary shares. Using United  Kingdom  statutory
powers  available  to  it  to  compulsorily  acquire  shares  not
purchased in the Tender Offer, CE Electric expects to acquire the
remaining Northern shares by April 30, 1997.

      As  of  March 17, 1997, the Company had contributed  to  CE
Electric  approximately  $410 million of the  approximately  $1.3
billion  required  to  acquire all  of  Northern's  ordinary  and
preference shares in connection with the Tender Offer and PKS had
contributed  $176  million to CE Electric for such  purpose.  The
Company  obtained  such  funds  from  cash  on  hand,  short-term
borrowings,  and borrowings of approximately $100  million  under
the  CalEnergy  Credit Facility. Borrowings under  the  CalEnergy
Credit  Facility were repaid in full on February  27,  1997.  The
remaining   funds  necessary  to  consummate  the  Tender   Offer
(approximately  $734  million)  will  be  provided  from  capital
contributions  or  loans to be made to CE Electric  by  its  sole
shareholder,  CE  Electric Holdings, which  has  entered  into  a
pounds  sterling  560 million (approximately $959  million)  Term
Loan  and  Revolving Facility Agreement, dated as of October  28,
1996 (the "U.K. Credit Facility"). The Company has not guaranteed
nor  is  it  otherwise subject to recourse for  amounts  borrowed
under  the  U.K.  Credit Facility. As of  January  31,  1997,  CE
Electric Holdings had borrowed approximately pounds sterling  321
million  (approximately  $550  million)  under  the  U.K.  Credit
Facility  to  pay  for  Northern ordinary and  preference  shares
purchased to date.

      Northern  is one of the twelve Regional Electric  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  is  primarily
engaged  in  the  distribution  and  supply  of  electricity   to
approximately  1.5  million customers.  Northern  was  granted  a
Public Electricity License ("PES") under the Electricity Act 1989
("Electricity  Act")  to  distribute and  supply  electricity  in
Northern's   authorized  area  ("Authorized  Area").   Northern's
Authorized  Area  covers approximately 14,400  square  kilometers
with  a  population  of  approximately  3.2  million  people  and
includes  the counties of Northumberland, Tyne and Wear,  Durham,
Cleveland and North Yorkshire. Northern distributes and  supplies
electricity  outside its Authorized Area pursuant to second  tier
PES licenses. Through its subsidiaries, Northern also is involved
in   non-regulated  activities,  including  the   generation   of
electricity,  electrical appliance retailing and gas  exploration
and production.

      Since  its  reorganization  in 1995,  Northern's  principal
assets  are the capital stock of the subsidiaries and all of  the
assets  used by such subsidiaries in their businesses.   Each  of
the  subsidiaries  focuses on its own particular  objectives  and
customers  and  each has its own employees and  management  team.
Northern  provides  a  number  of services  to  the  subsidiaries
including telecommunications, electrical distribution and supply,
transportation  and  technology  support,  and  certain  of   the
subsidiaries provide services to each other.

The Global Power Generation Market

       The  opportunity  for  independent  power  generation  has
expanded  from a United States market consisting of  cogeneration
and  small  power  production projects to  a  global  competitive
market   for  power  generation.  Many  foreign  countries   have
initiated restructuring and privatization policies that encourage
the  development of independent power generation and, to a lesser
extent, independent distribution and supply of power.

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

      However, as the size of the United States independent power
market  has  increased,  available domestic  power  capacity  and
competition in the industry have also significantly increased and
the  need for new generating capacity has been reduced. Over  the
past  decade,  obtaining  a power sales contract  from  a  United
States  utility  has  generally  become  increasingly  difficult,
expensive  and competitive. Many states now require  power  sales
contracts  to be awarded through competitive bidding, which  both
increases the cost of obtaining such contracts and decreases  the
chances   of  obtaining  such  contracts  as  bids  significantly
outnumber  awards  in  most competitive solicitations.  Utilities
also  recently  have made more efficient use  of  their  existing
plants,  through improved availability, extended plant lives  and
repowering,  and  have  begun to take  advantage  of  financially
attractive bulk power purchase opportunities. The Federal  Energy
Policy  Act  of  1992  and  several  recent  federal  and   state
legislative  and regulatory initiatives are expected  to  further
increase domestic competition.

      During  1995 and 1996, many states began to accelerate  the
movement toward more competition in the electric power market and
extensive  federal  and state legislative and regulatory  reviews
are  underway  in  an  effort  to further  such  competition.  In
addition, recent deregulation and industry restructuring activity
may  cause certain utilities or other contract parties to attempt
to  renegotiate  contracts or otherwise  fail  to  perform  their
contractual obligations, which in turn could adversely affect the
Company's  results  of operations. In particular,  the  state  of
California  has  adopted  a  bill  to  restructure  the  electric
industry   by   providing  for  a  phased-in  competitive   power
generation  industry,  with a power pool and  independent  system
operator,  and  for  direct access to generation  for  all  power
purchasers    outside   the   power   exchange   under    certain
circumstances.   The  bill  provides  that  existing   qualifying
facility  power  sales agreements will be honored.  Other  states
have  or  are expected to take similar steps aimed at  increasing
competition  by  restructuring the  electric  industry,  allowing
retail  competition  and  deregulating most  electric  rates.  In
addition,  recent  federal legislation has  been  proposed  which
would  repeal  PURPA and PUHCA, respectively. The Company  cannot
predict  the  final  form  or timing  of  the  proposed  industry
restructuring or the result on its operations.

       Internationally,  large  amounts  of  new  electric  power
generating  capacity  are required in developing  countries.  The
movement  toward privatization in some developing  countries  has
created  significant new markets outside the  United  States.  In
1990  the  World  Bank estimated that developing countries  would
need  approximately  380,000 MW of new power generating  capacity
through  the end of the decade. The need for such rapid expansion
has caused many countries to select private power development  as
their   only  practical  alternative  and  to  restructure  their
legislative   and   regulatory   systems   to   facilitate   such
development. The Company believes that this significant need  for
power has created strong local support for private power projects
in  many foreign countries and has increased the availability  of
attractive long-term power contracts. The Company intends to take
advantage  of opportunities in these new markets and to  develop,
construct  and acquire power generation, distribution and  supply
and  related  energy  projects  meeting  its  strategic  criteria
outside the United States.

      The  international independent power production  market  is
characterized by numerous strong and capable competitors, many of
which  have more extensive and more diversified developmental  or
operating  experience  (including international  experience)  and
greater  financial  resources than the  Company.  Many  of  these
competitors also participate in the domestic market.

The Electric Utility Industry in the United Kingdom

      In  connection  with the privatization of  the  electricity
industry  in the United Kingdom, distribution assets  in  England
and  Wales,  previously owned indirectly by  the  United  Kingdom
government, were allocated among the RECs, licensing requirements
were established for the RECs and price controls were implemented
in  the  areas of distribution and supply. In England and  Wales,
most  of  the  state-owned generation assets (other than  nuclear
facilities)  were allocated to two generating companies  and  the
high  voltage transmission assets were allocated to The  National
Grid  Company  plc  ("NGC"),  a wholly-owned  subsidiary  of  The
National  Grid  Group plc ("NGG"). The high voltage  transmission
system  in England and Wales, which is generally referred  to  as
the "national grid" transmission system, transfers electricity in
bulk   from  the  power  stations  to  the  regional  and   local
distribution systems.

      Distributors  transfer  electricity  over  their  networks,
generally  at lower voltage than the national grid,  from  supply
points  on the national grid to final consumers. The distribution
systems  in England and Wales are owned by the 12 RECs. Virtually
all   customers  in  England  and  Wales  are  connected  to  the
distribution system of the RECs and have no effective  choice  as
to   the  distribution  system  from  which  they  receive  their
electricity.  Distribution  prices  charged  by  the   RECs   are
regulated  by the Distribution Price Control Formula (as  defined
below).

      Suppliers sell electricity to end users. Each REC has a PES
license  which  authorizes  it  to  supply  electricity  to   any
customers within its authorized area. Electricity customers  fall
into two categories: Franchise Supply Customers and Non-Franchise
Supply   Customers.   Until  March  31,  1998,  Franchise  Supply
Customers are those with demands of not more than 100kW and  such
customers can be supplied only by the PES license holder for  the
authorized  area. Non-Franchise Supply Customers are  those  with
premises  with  demands exceeding 100kW.  Prices  for  supply  of
electricity  to Franchise Supply Customers are regulated  by  the
Supply  Price  Control Formula (as defined  below).  The  current
supply  price control is expected to be replaced effective  March
31,  1998,  at  which time the authorized area supply  market  is
expected  to  be open to any competitors that have  obtained  the
necessary  license, which is generally referred to as  a  "second
tier  license."  Non-Franchise Supply Customers  already  may  be
supplied  by any entity that has obtained a second tier  license.
Such  second  tier  suppliers, including  Northern,  compete  for
business nationally and at prices determined by competitive  bids
or negotiation.

Geothermal Energy
                                
      Geothermal  energy  is  a  clean, renewable  and  generally
sustainable  energy  source that, because  it  does  not  utilize
combustion   in   the   production   of   electricity,   releases
significantly lower levels of emissions than result  from  energy
generation  based  on  the  burning of fossil  fuels.  Geothermal
energy  is derived from the natural heat of the earth when  water
comes sufficiently close to hot molten rock to heat the water  to
temperatures of 400 degrees Fahrenheit or more. The heated  water
then  ascends  toward  the surface of  the  earth  where  it,  if
geological conditions are suitable for its commercial extraction,
can  be  extracted  by  drilling  geothermal  wells.  The  energy
necessary  to  operate  a  geothermal power  plant  is  typically
obtained  from  several  such  wells,  which  are  drilled  using
established  technology similar to that employed in the  oil  and
gas industry.

      Geothermal  production  wells are normally  located  within
approximately  one to two miles of the power plant as  geothermal
fluids  cannot be transported economically over longer distances.
From the well heads, the heated fluid flows through pipelines  to
a  series  of separators where it is separated into water,  brine
and  steam. The steam is passed through a turbine which drives  a
generator  to  generate electricity. Once the  steam  has  passed
through  the turbine, it is then cooled and condensed  back  into
water  which, along with any brine, is returned to the geothermal
reservoir  via  injection wells. The geothermal  reservoir  is  a
renewable source of energy if natural ground water sources and re-
injection  of extracted geothermal fluids are adequate  over  the
long  term  to  replenish  the  geothermal  reservoir  after  the
withdrawal of geothermal fluids.

      The  generation of electric power from geothermal resources
has certain advantages when compared to other methods of electric
power    generation.   Geothermal   energy   facilities   produce
significantly  less  emissions than  fossil  fuel  power  plants.
Geothermal energy facilities typically have higher capital  costs
due  to  the front end cost of reservoir development but tend  to
have  significantly lower variable costs than fossil  fuel  based
power  plants  because  fuel  does  not  need  to  be  separately
purchased.  The utilization of geothermal power is  preferred  by
certain governments so as to minimize the import, or maximize the
export,  of hydrocarbons. Geothermal power facilities also  enjoy
certain tax benefits in the United States and are eligible to  be
qualifying  facilities ("QFs") under PURPA,  which  provides  for
certain beneficial federal regulatory treatment.

      Geothermal  exploration,  development  and  operations  are
subject  to  uncertainties similar to those typically  associated
with oil and gas exploration and development, including dry holes
and uncontrolled releases. Because of the geological complexities
of  geothermal  reservoirs, the geographic area  and  sustainable
output  of geothermal reservoirs can only be estimated and cannot
be  definitively established. There is, accordingly, a risk of an
unexpected decline in the capacity of geothermal wells and a risk
of  geothermal  reservoirs  not being  sufficient  for  sustained
generation of the electrical power capacity desired. In addition,
geothermal power resources usually occur in areas of high seismic
activity.  There  can  be no assurance that earthquake,  property
damage  or  business interruption insurance will be  adequate  to
cover  all  potential losses sustained in the  event  of  serious
seismic disturbances or that such insurance will be available  on
commercially reasonable terms.

      The  success of a geothermal project depends on the quality
of  the  geothermal resource and operational factors relating  to
the extraction of the geothermal fluids involved in such project.
The  quality of a geothermal resource is affected by a number  of
factors, including the size of the reservoir, the temperature and
pressure  of the geothermal fluids in such reservoir,  the  depth
and capacity of the production and injection wells, the amount of
dissolved  solids  and  noncondensible gases  contained  in  such
geothermal  fluids, and the permeability of the  subsurface  rock
formations  containing  such geothermal resource,  including  the
presence,  extent and location of fractures in  such  rocks.  The
quality  of  a geothermal resource may decline as a result  of  a
number  of  factors, including the intrusion of lower-temperature
fluid  into  the  producing zone. An incorrect  estimate  by  the
Company  of  the quality of geothermal resource, or a decline  in
such  quality,  could  have  a material  adverse  effect  on  the
Company's results of operations.

      Geothermal  energy  is most prevalent where  the  different
sections   or  plates  of  the  Earth's  crust  meet.  Productive
geothermal resources are found throughout the Pacific Rim (the so-
called  "Ring  of  Fire"), including the western  United  States,
Latin  America, Hawaii, Indonesia, the Philippines, Malaysia  and
New   Zealand.  These  areas  are  experiencing  high  rates   of
population   growth  and  increased  demand  for   new   electric
generating capacity.

Strategy

      General.   The Company's strategy remains focused primarily
upon  continued  growth  in  its core power  generation  business
through  the development of new projects, enhancement of existing
and   acquired  assets'  performance,  and  the  acquisition   of
companies  and  projects  that  diversify  the  Company's   power
generation technologies and enhance its competitive capabilities.
The Company also intends to pursue strategic expansion into other
aspects  of the global power business, including the distribution
and supply of electricity, in order to diversify its business and
cash  flows, develop and enhance its distribution, marketing  and
power pool skills and increase its competitive capabilities.  The
Northern  acquisition  was implemented  in  furtherance  of  this
aspect  of the Company's strategy. The Company believes that  its
existing  assets, strengths and skills, coupled  with  Northern's
distribution  and supply skills, its experience  in  the  largely
deregulated  United  Kingdom  power  market  and  the   resulting
diversification  in the Company's assets and geographic  location
will  position the Company to maximize its ability to participate
successfully   (by   way   of  acquisition   or   otherwise)   in
opportunities  expected to be created in the next  few  years  by
restructurings  in  the  United States and  other  global  energy
markets. The Company also selectively will seek opportunities  to
expand beyond power generation, distribution and supply in  areas
related to these core businesses, such as power transmission  and
gas production and supply, if such opportunities will enhance the
Company's competitive capabilities and financial position.

      Power Generation.  The Company presently believes that  the
international independent power market holds the majority of  new
opportunities   for   financially   attractive   private    power
development in the next several years, in large part because  the
demand  for  new generating capacity is growing more  rapidly  in
emerging  nations  than in the United States. In  developing  its
international   strategy,   the   Company   pursues   development
opportunities  in countries that it believes have  an  acceptable
risk  profile  and where the Company's resource  development  and
operating experience, project development and financing expertise
or strategic relationship with PKS or local partners are expected
to  provide  it  with a competitive advantage. Domestically,  the
Company   is   focusing  on  environmentally  responsible   power
generation  opportunities in which it believes  it  has  relative
competitive  advantages due to its technical, project management,
project financing and operating expertise. In the near term,  the
Company  expects that its continued domestic generation expansion
will  be  accomplished  primarily through selected  acquisitions,
including  acquisitions of partially developed or existing  power
generating  projects  and contracts, although  the  Company  will
consider     appropriate    domestic    greenfield    development
opportunities  if they arise. The Company is also evaluating  the
potential  opportunities  of direct access  and  power  marketing
through use of retail wheeling.

      In pursuing its international strategy, the Company intends
to  own  a  significant equity interest in, and to  operate,  the
projects  it  develops  or acquires. In  order  to  compete  more
effectively internationally, the Company's strategy is to attempt
to  diversify its project portfolio from a country,  fuel  source
and  customer  perspective,  extend  its  future  equity  funding
capacity through joint ventures and utilize fixed-price,  turnkey
construction  contracts  with  contractors  experienced  in   the
construction of power plants or other infrastructure  facilities.
The  Company  also  believes  that it  is  important  in  foreign
transactions  to  work with local partners who are  knowledgeable
concerning  local culture, politics and commercial practices  and
who   provide   a  visible  local  presence  and  local   project
representation.

      With  respect  to emerging market projects,  the  Company's
policy  is  to attempt to minimize currency risks, including  the
devaluation of local currencies versus the United States  dollar,
as   well   as   the  risk  of  availability  of  hard   currency
convertibility.  To  date,  all of the Company's  executed  power
sales  contracts  contain  provisions that  index  the  Company's
revenues  to United States dollars or provide for the payment  of
capacity  payments  in  United  States  dollars.  To  the  extent
possible,  the  Company  attempts  to  secure  "political   risk"
insurance  from  government agencies  such  as  OPIC  or  similar
multilateral agencies or commercial sources to limit its risk  in
emerging market countries. In addition, the Company endeavors  to
involve  the  World Bank, export credit agencies or  multilateral
funding  sources  in  its international project  financings.  The
Company  believes  multilateral lending agencies,  export  credit
agencies,  international commercial financing and political  risk
insurance  are  generally  available  for  certain  international
private  power projects, particularly those utilizing  indigenous
fuel   sources   in   renewable   or  otherwise   environmentally
responsible generating facilities. The Company believes that  the
involvement  of these institutions will enhance an  international
project's position in emerging market countries.

      The  Company  has an international joint venture  agreement
with  PKS  which  the  Company believes  enhances  the  Company's
capabilities   in  foreign  power  markets.  The  joint   venture
agreement  is limited to international power project  development
activities and provides that, if both the Company and  PKS  agree
to  participate  in  a project, they will share  all  development
costs  equally. The Company and PKS each will provide 50% of  the
equity  required for financing a project developed by  the  joint
venture,  and  the  Company  will  receive  from  the  project  a
development  fee  (generally  1% of  project  capital)  and  will
operate  and manage such project for a fee. The agreement creates
a  joint  development  structure under which,  on  a  project  by
project  basis,  the  Company will be  the  development  manager,
managing  partner  and/or  project  operator,  an  equal   equity
participant  with PKS and PKS will be an equal equity participant
and  the  preferred  turnkey construction contractor.  The  joint
venture  agreement may be terminated by either party on  15  days
written notice, provided that such termination cannot affect  the
pre-existing contractual obligations of either party.

       Domestically,  the  Company  is  presently   focusing   on
generation  opportunities in which it believes  it  has  relative
competitive   advantages   due  to  its   geotechnical,   project
management,  project  financing  and  operating  expertise.    In
addition,  the  Company expects to continue diversification  into
other  environmentally responsible sources  of  energy  primarily
through   selected   acquisitions,  including   acquisitions   of
partially  developed  or existing power generating  projects  and
contracts.  The Company is also evaluating the potential  impacts
and opportunities of direct access and retail wheeling.

        Distribution,    Supply   and   Other   Related    Energy
Businesses.  The Company believes that the power distribution and
supply  businesses  present  significant  investment  and  return
opportunities  at  the present time in selected foreign  markets,
such  as  the  United  Kingdom, and that power  distribution  and
supply skills will comprise a significant component of the  skill
base  required  to compete effectively in the United  States  and
other  global  power markets once those markets are substantially
deregulated  and  competitive.  The  Company  believes  that  the
impending  changes in the regulation of the United  States  power
markets will reflect many aspects of the United Kingdom model for
competitive generation, transmission, distribution and supply  of
energy.  Thus,  the  experience the  Company  will  gain  through
Northern's  operations  in  the  United  Kingdom  markets  should
strengthen  its ability to compete successfully as other  markets
are  also  deregulated. The current effort to  introduce  broader
wholesale and retail competition in the United States is expected
by  the  Company  to  result both in a  continuing  trend  toward
consolidation  among  domestic utilities  and  independent  power
producers and in the disaggregation (or unbundling) of vertically
integrated  utilities into separate generation, transmission  and
distribution  businesses. While this may  result  in  significant
increased  competition in each of these businesses,  the  Company
believes  that the acquisition of Northern and the experience  to
be  gained by it in the competitive and substantially deregulated
United  Kingdom  market,  coupled  with  the  Company's  existing
development and generation capabilities, will provide the Company
with  the  opportunity  to capitalize on  the  opportunities  and
challenges   of  an  increasingly  deregulated  and   competitive
domestic  market  for the generation, transmission,  distribution
and supply of energy. Similar opportunities also are expected  to
occur in other countries as various international markets undergo
similar restructuring. The Company believes that as the wholesale
and  retail energy markets become more competitive, the principal
factor determining success is likely to be price, and to a lesser
extent,   reliability,  availability  of  capacity  and  customer
service. Accordingly, its acquisitions of domestic utility assets
in  a deregulated environment will have to meet defined criteria,
including  the  potential  to  lower  costs,  increase  long-term
efficiency and competitiveness and provide an acceptable rate  of
return and benefit to the Company and its stockholders.

The Company's Power Generation Project Portfolio
                                
      The Company has net ownership interests of an aggregate  of
(i)  1,309  MW  in  20  projects  in  operation  representing  an
aggregate  net  capacity  of  3,201  MW  of  electric  generating
capacity,  (ii)  314  MW  in  five  projects  under  construction
representing  an  aggregate net capacity of 564  MW  of  electric
generating  capacity  and  (iii)  573  MW  in  six  projects   in
development  stages with signed power sales agreements  or  under
award  representing  an aggregate net capacity  of  1,260  MW  of
electric  generating  capacity.  The  following  table  sets  out
certain  information  concerning  various  Company  projects   in
operation,  under  construction and in  development  pursuant  to
signed power sales agreements or awarded mandates.
                                
<TABLE>
<CAPTION>

             International Power Generation Projects
                                
Projects in Operation (1)

                              FACILITY     NET                 PROJECT
PROJECT                         NET        OWNER              COMMERCIAL    
                       FUEL   CAPACITY   INTEREST             OPERATIION    CONTRACT        CONTRACT       POWER
                      SOURCE (IN MW)(2)   (IN MW)  LOCATION     DATE      EXPIRATION(3)       TYPE       PURCHASER(4)
<S>                     <C>    <C>        <C>      <C>           <C>         <C>            <C>           <C>
Upper Mahiao (9)        Geo      119       119     Leyte, the    1996        CO+10          Build, Own    PNOC-EDC
                                                   Philippines                              Transfer      (GOP)(5)

Malitbog-Unit I (9)     Geo       72        72     Leyte, the    1996        CO+11          Build, Own    PNOC-EDC
                                                   Philippines                              Transfer      (GOP)(5)

Teesside Power          Gas    1,875        202    England       1993        CO+15          Negot.         Various
Limited

Total in Operation             2,066        393

Projects in Construction

</TABLE>
<TABLE>
<CAPTION>
                               FACILITY      NET                 PROJECT
                                 NET        OWNER               COMMERCIAL
                       FUEL    CAPACITY    INTEREST             OPERATION      CONTRACT     CONTRACT        POWER
PROJECT               SOURCE  (IN MW)(2)   (IN MW)    LOCATION     DATE      EXPIRATION(3)    TYPE       PURCHASER(4)
Mahanagdong(6)         Geo       165         74       Leyte, the    1997         CO+10       Build, Own    PNOC-EDC
                                                      Philippine                             Transfer      (GOP)(5) 
<C>                   <C>        <C>        <C>       <C>           <C>          <C>         <C>           <C>
Malitbog-Unit          Geo       144        144       Leyte, the    1997         CO+10       Build, Own    PNOC-EDC
II and III                                            Philippines                            Transfer      (GOP)(5)

Casecnan(6)(7)        Hydro      150         52       Luzon, the    1999         CO+20       Build, Own    NIA (GOP)(5)
                                                      Phillipines                            Transfer

Dieng Unit I(6)       Geo         55         26       Central Java  1997         CO+30       Build, Own    PLN (GOI)
                                                      Indonesia                              Transfer

Viking                Gas         50         18       England       1997         CO+10       Negot.        Northern

Total in Construction            564        314

Projects with Signed Power Sales Contracts or Awarded Development Rights
</TABLE>
<TABLE>
<CAPTION>
                             FACILITY      NET                      PROJECT 
                               NET        OWNER                     COMMERCIAL
                     FUEL    CAPACITY    INTEREST                   OPERATION      CONTRACT       CONTRACT          POWER
PROJECT             SOURCE   (IN MW)(2)  (IN MW)    LOCATION           DATE      EXPIRATION(3)      TYPE         PURCHASER(4)
<S>                  <C>        <C>        <C>      <C>              <C>             <C>         <C>             <C>
Dieng(6)             Geo        345        162      Central, Java    1998-1999       CO+30       Build, Own      PLN (GOI)
                                                    Indonesia                                    Transfer

Patuha(6)            Geo        400        176      Western, Java    1998-1999       CO+30       Build, Own      PLN (GOI)
                                                    Indonesia                                    Transfer

Bali(6)              Geo        400        120      Bali,            1998-1999       CO+30       Build,          PLN (GOI)
                                                    Indonesia                                    Transfer

Alto Peak            Geo         70         70      Leyte, the          1998          CO+10      Build, Own      PNOC-EDC
                                                    Philippines                                  Transfer        (GOP)(5)

Total Contracted/Awarded      1,215         528

Total International Project   3,845       1,235

</TABLE>

      (1)The  Company  operates  all  such  projects  other  than
Teesside.  This  chart does not include 47 small  scale  combined
heat and power facilities that an indirect Northern Electric  plc
subsidiary  operates  and a 5 MW diesel  power  generating  plant
located  in  Northallerton, England that a Northern Electric  plc
subsidiary  operates  (in  which the  Company  has  a  3  MW  net
ownership interest).

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

     (3)Commercial Operation ("CO") plus number of years.

       (4)PNOC-Energy   Development   Corporation   ("PNOC-EDC");
Government  of  the  Philippines  ("GOP");  P.T.  PLN   (Persero)
("PLN"); Government of Indonesia ("GOI"); and Philippine National
Irrigation Administration ("NIA").

      (5)Government of the Philippines undertaking supports PNOC-
EDC's and NIA's respective obligations.

     (6)PKS has elected to exercise its ownership option pursuant
to its joint venture agreement with the Company.

     (7)NIA also purchases water from this facility.

      (8)Significant  contingencies exist in respect  of  awards,
including  without  limitation, the  need  to  obtain  financing,
permits and licenses, and the completion of construction.

      (9)Construction of these facilities has been completed and,
accordingly, these facilities have been "deemed complete" by PNOC-
EDC  and are currently receiving the full capacity payments under
the  "take  or pay" provisions of their contracts with  PNOC-EDC,
pending  NPC  making available to these projects a full  capacity
transmission  line.  In  the  interim  (until  a  full   capacity
transmission  line  is  in place), the Upper  Mahiao  project  is
currently supplying up to 40 MW of electric generation at  PNOC's
request on a daily dispatch basis.
                                
<TABLE>
<CAPTION>
                                
               Domestic Power Generation Projects
                                
Projects in Operation
                                             NET                      PROJECT
                           FACILITY NET   OWNERSHIP                   COMMERCIAL   CONTRACT                  POWER
                   FUEL    CAPACITY (IN   INTEREST                    OPERATION   EXPIRATION    CONTRACT   PURCHASER
PROJECT            SOURCE  MW)(1)(2)(3)   (IN MW)(2)  LOCATION          DATE         (5)          TYPE        (4)
<S>                 <C>        <C>           <C>      <C>              <C>         <C>             <C>      <C>
Navy I              Geo         88           41       China Lake, CA   8/1987      8/2011          SO4      Edison

BLM                 Geo         88           42       China Lake, CA   3/1989      3/2019          SO4      Edison

Navy II             Geo         88           44       China Lake, CA   1/1990      1/2010          SO4      Edison

Vulcan              Geo         34           34       Imperial         2/1986      2/2016          SO4      Edison
                                                      Valley, CA

Hoch (Del Ranch)    Geo         38           38       Imperial         1/1989      12/2018         SO4      Edison
                                                      Valley, CA

Elmore              Geo         38           38       Imperial         1/1989      12/2018         SO4      Edison
                                                      Valley, CA

Leathers            Geo         38           38       Imperial         1/1990      12/2019          SO4     Edison
                                                      Valley, CA

Salton Sea I        Geo         10           10       Imperial         7/1987      6/2017          Negot.   Edison
                                                      Valley, CA

Salton Sea II      Geo          20           20       Imperial         4/1990      4/2020          SO4      Edison
                                                      Valley, CA

Salton Sea III     Geo          50           50       Imperial         2/1989      2/2019          SO4      Edison
                                                      Valley, CA

Salton Sea IV      Geo          40           40       Imperial          6/1996     6/2026          Negot.   Edison
                                                      Valley, CA

Saranac            Gas         240          180       Plattsburgh, NY   6/1994     6/2009          Negot.   NYSEG

Power Resources    Gas         200          200       Big Spring, TX    6/1988     9/2003          Negot.   TUEC

NorCon             Gas          80           64       Erie, PA         12/1992    12/2017          Negot.   NIMO

Yuma Cogen.        Gas          50           50       Yuma, AZ          5/1994     5/2024          Negot.   SDG&E

Roosevelt Hot      Geo          23           17       Milford, UT       5/1984     1/2021          Gathered UP&L
                                                                                                    Steam

Desert Peak        Geo          10           10       Desert Peak, NV  12/1985      Not            Negot.   SPPC
                                                                                   Fixed
Total in Operation           1,135          916 

Projects with Signed Power Sales Contracts or Awarded Development Rights
</TABLE>
<TABLE>
<CAPTION>
                                               NET                 PROJECT
                              FACILITY NET   OWNERSHIP             COMMERCIAL   CONTRACT
                      FUEL      CAPACITY     INTEREST              OPERATION   EXPIRATION   CONTRACT   PURCHASER
PROJECT              SOURCE   MW)(1)(2)(3)   (IN MW)     LOCATION     DATE        (5)         TYPE        (4)
<S>                   <C>       <C>         <C>         <C>          <C>         <C>          <C>         <C>
Salton Sea Mineral    Geo          15           15       Imperial     TBD         TBD         TBD         TBD
Extraction(7)                                            Valley, CA

Glass                 Geo          30           30       Siskiyou     2000       CO+20        Negot.       BPA
Mountain(7)(8)                                           County, CA

Total Contracted/Awarded           45           45

Total Domestic Projects         1,180          961

Total Projects                  5,025        2,196

</TABLE>

      (1)Excludes  royalty  income received  by  Magma  from  the
Mammoth and East Mesa plants.

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

      (3)With  respect to the Vulcan, Hoch (Del  Ranch),  Elmore,
Leathers,  Salton  Sea  I,  Salton Sea  II  and  Salton  Sea  III
Projects, this represents contract nameplate.

      (4)Southern California Edison Company ("Edison"); San Diego
Gas  &  Electric  Company ("SDG&E"); Utah Power &  Light  Company
("UP&L"); Sierra Pacific Power Company ("SPPC"); Bonneville Power
Administration ("BPA"); New York State Electric & Gas Corporation
("NYSEG"); Texas Utilities Electric Company ("TUEC"); and Niagara
Mohawk Power Corporation ("NIMO").

     (5)Commercial Operation (CO) plus number of years.

     (6)Represents the electrical equivalent of delivered steam.

      (7)Actual MW may vary depending on operating and  reservoir
conditions  and  final  plant design.  Significant  contingencies
exist  in  respect of awards, including without  limitation,  the
need   to  obtain  financing,  permits  and  licenses,  and   the
completion of construction.

      (8)The Newberry project has been moved to Glass Mountain to
take  advantage  of  better reservoir conditions  at  the  latter
location.  A settlement agreement has been executed with  BPA  to
recognize  the move, subject to completion of certain  activities
including an environmental impact statement
                                
                                
             International Power Generation Projects
                                
Projects in Operation or Construction

     The Company has two Philippines power projects in operation:
the  Upper Mahiao geothermal project (119 net MW) and Unit  I  of
the  Malitbog  geothermal project (72  net  MW).  Both  of  these
projects recently achieved "deemed completion" status under their
contracts  and  are  receiving the full capacity  payments  under
their "take or pay" provisions pending completion by the National
Power  Corporation of the Philippines ("NPC") of a full  capacity
transmission line. Currently, the Upper Mahiao plant is providing
up  to  40 MW (the capacity of the interim transmission line)  to
PNOC-EDC on a daily dispatch basis.

      The Company has five international power projects currently
under   construction,  which  are  located  in  the  Philippines,
Indonesia  and  England.  These projects  total  564  net  MW  of
capacity,  consisting of three such projects in the  Philippines,
the Mahanagdong geothermal project (165 net MW), Unit II and Unit
III  of  the  Malitbog geothermal project (144 net  MW)  and  the
Casecnan  combined irrigation and hydroelectric project (150  net
MW),  one  project  in  Indonesia, the Dieng  Unit  I  geothermal
project  (55  net MW), and a project in England, the  Viking  gas
fired  project  (50  net MW). The Company has  an  aggregate  net
ownership  interest of 314 MW of electric generating capacity  in
these  projects. Dieng Unit I constitutes the first  phase  of  a
planned  development of approximately 1,000  MW  under  award  in
Indonesia.

      The  Philippines.  According to the 1995 Power  Development
Program  (1995-2005)  (the "PDP") of NPC,  industrial  growth,  a
rising  standard  of  living and an expanding power  distribution
network have resulted in increased demand for electrical power in
the  Philippines by an average of 6% per year since 1987. NPC has
projected  that  over the next 10 years the need  for  additional
generating capacity in the Philippines will exceed 14,000 MW.

      The  PDP  proposes  to meet this demand by  increasing  the
participation of the private sector in power generation to 32% in
2000,  and  to 61% in 2005, through direct sales to utilities  by
independent  power  producers  ("IPPs")  and  the  use  of   BOOT
projects.  NPC  also  will offer existing  power  plants  to  the
private   sector   through   rehabilitate-operate-maintain    and
rehabilitate-operate-lease   arrangements.   In   addition,   the
Department  of  Energy  of  the Philippines  ("DOE"),  which  was
created  in  part to deregulate the energy sector  and  privatize
government  energy  agencies,  has submitted  to  the  Philippine
Congress  a  plan  to  further  restructure  and  liberalize  the
electrical power market, including separating the generating  and
transmission   functions  of  the  NPC  and  introducing   retail
wheeling.  The  government entities that will lead implementation
of  the  restructuring will be DOE, NPC and the Energy Regulatory
Board  ("ERB"),  the  agency  that  regulates  retail  prices  of
electricity and petroleum projects.

      Demand  growth is expected to increase as industrialization
continues,  living  standards rise  and  the  power  distribution
network  expands. According to the PDP, for the  period  1996  to
2000,  projected peak power demand is estimated  to  increase  by
approximately  60%,  64%,  and 90% for Luzon,  the  Visayas,  and
Mindanao,  respectively. For the country,  total  projected  peak
power  is estimated to increase by 3,826 MW or 65% from  1996  to
2000.  For  the  period  2001 to 2005, projected  peak  power  is
estimated  to  increase by approximately 50%, 43%,  and  59%  for
Luzon,  the Visayas, and Mindanao, respectively. For the country,
total  projected peak power is estimated to increase by 5,459  MW
or 51% from 2001 to 2005.

      The  objective  of  the  electricity  supply  industry  was
initially set forth by Presidential Decree No. 40, dated November
7,  1972  (the "Decree"). The Decree called for the hastening  of
the electrification of the country, particularly the rural areas,
and  specifically mandates NPC to set up electricity transmission
line grids and generation facilities on the major islands of  the
country.

      In  1993, the Philippine Congress, pursuant to Republic Act
7648,  granted  President Ramos emergency powers  to  remedy  the
Philippine energy crisis, including authority to (i) exempt power
projects  from  public bidding requirements, (ii) increase  power
rates and (iii) reorganize NPC. Until 1987, NPC had a monopoly on
power  generation  and transmission in the Philippines.  In  that
year  the  government  elected  to  tap  the  private  sector  to
implement  power  generation projects by passing Executive  Order
No.  215, which authorized private sector development of priority
infrastructure. In 1991, the Philippine Congress enacted Republic
Act  No.  6957, which authorized private development of  priority
infrastructure  projects  on  a  "build-operate-transfer"  and  a
"build-transfer" basis. In addition, under that Act,  such  power
projects  were made eligible for certain tax benefits,  including
exemption from Philippine national income taxes for at least  six
years  and  exemption from, or reimbursement for, customs  duties
and  value  added  taxes on capital equipment to be  incorporated
into  such projects. In 1994, certain amendments to Republic  Act
No. 6957 were approved by the Philippine Congress and signed into
law  (R.A. 7718). Among other things, such amendments provide for
the  financing  of  "unsolicited proposals" on a  "build-operate-
transfer"   basis.  As  a  result,  as  of  the  end   of   1994,
approximately  39%  of  NPC's total  system  capacity  was  being
operated  and  maintained  by the private  sector  under  various
schemes of private power generation.

      In  an  effort to remedy the shortfall of electricity,  the
Philippines,  NPC and PNOC-EDC continue to jointly  solicit  bids
for private power projects. Among private power projects selected
through  this  solicitation process were the  Upper  Mahiao  (the
"Upper Mahiao Project"), Mahanagdong (the "Mahanagdong Project"),
Malitbog  (the "Malitbog Project") and Alto Peak (the "Alto  Peak
Project")  geothermal  power projects,  as  described  below.  In
addition,  the Casecnan ("Casecnan Project") combined  irrigation
and   hydroelectric   power  project  was  awarded   through   an
"unsolicited proposal." Geothermal power has been identified as a
preferred alternative by the Government of the Philippines due to
the  domestic availability and the minimal environmental  effects
of  geothermal  power  in  comparison to  other  forms  of  power
production.  PNOC-EDC, which is responsible  for  developing  the
Philippines' domestic energy sources, has been successful in  the
exploration and development of geothermal resources.

      Upper  Mahiao.   In 1994, the Company closed the  financing
and commenced construction of the Upper Mahiao Project, a 119 net
MW  geothermal project to be located in the Greater Tongonan area
of  the  island  of  Leyte in the Philippines. The  Upper  Mahiao
facility  was "deemed complete" by PNOC-EDC as of June 17,  1996,
meaning  that construction of the facility was completed on  time
but   the  required  full  capacity  transmission  line  was  not
completed and provided to CE Cebu Geothermal Power Company,  Inc.
("CE  Cebu"), a Philippine corporation that is approximately 100%
indirectly owned by the Company. During deemed completion,  PNOC-
EDC  is  required to pay all capacity fees under the take or  pay
provisions of the contract. PNOC-EDC is paying such capacity fees
on a timely basis.

      Based  on  a  recent agreement with PNOC-EDC,  the  "deemed
completion" has been modified, effective September 13,  1996,  to
allow  delivery  of  up  to 40 MW of power  through  a  temporary
transmission facility. This amendment will allow for  payment  to
CE  Cebu  of  fees for energy delivered in addition to continuing
the  payment for the full capacity fee. CE Cebu sells 100% of its
capacity  on a "take-or-pay" basis (described below) to PNOC-EDC,
which  in  turn  sells the power to NPC for distribution  to  the
island of Cebu, located about 40 miles west of Leyte.

      The  Upper  Mahiao  Project had a  total  project  cost  of
approximately    $218   million,   including   interest    during
construction,  project  contingency  costs  and  a  debt  service
reserve  fund.  A  consortium  of  international  banks  provided
approximately  $162  million  in  project-financed   construction
loans, supported by political risk insurance from the Ex-Im Bank.
The  construction loan is expected to be converted to a term loan
promptly after NPC completes the full capacity transmission line,
which is currently expected in early 1997. The largest portion of
the  term  loan  for the project will also be provided  by  Ex-Im
Bank.  The  Company's  equity contribution to  the  Upper  Mahiao
Project  is  $56  million. Subject to the pledge of  the  project
company's  stock  to the lenders, the Company  has  arranged  for
political  risk insurance of its equity investment through  OPIC.
The financing is collateralized by all the assets of the project.

      Under the terms of an energy conversion agreement, executed
on  September 6, 1993 (the "Upper Mahiao ECA"), CE Cebu will  own
and   operate  the  Upper  Mahiao  Project  during  the  ten-year
cooperation period, after which ownership will be transferred  to
PNOC-EDC at no cost.

     The Upper Mahiao Project is located on land provided by PNOC-
EDC  at  no  cost. It will take geothermal steam and fluid,  also
provided  by PNOC-EDC at no cost, and convert its thermal  energy
into  electrical energy to be sold to PNOC-EDC on a "take-or-pay"
basis.  Specifically,  PNOC-EDC  is  obligated  to  pay  for  the
electric  capacity  that  is nominated  each  year  by  CE  Cebu,
irrespective  of whether PNOC-EDC is willing or  able  to  accept
delivery  of such capacity. PNOC-EDC will pay 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). The  Capacity
Fee  serves  to  recover the capital costs  of  the  project,  to
recover  fixed operating costs and to cover return on investment.
The  Energy  Fee is designed to cover all variable operating  and
maintenance  costs of the power plant. Payments under  the  Upper
Mahiao  ECA  will be 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, which will be  used  to
pay Philippine peso-denominated expenses. Significant portions of
the  Capacity  Fee  and Energy Fee will be indexed  to  U.S.  and
Philippine  inflation  rates,  respectively.  PNOC-EDC's  payment
requirements,  and its other obligations under the  Upper  Mahiao
ECA, are supported by the Government of the Philippines through a
performance undertaking.

      The  payment of the Capacity Fee is not excused if PNOC-EDC
fails  to  deliver  or remove the steam or  fluids  or  fails  to
provide  the  transmission facilities, even if  its  failure  was
caused  by  a  force  majeure event. In addition,  PNOC-EDC  must
continue  to  make  Capacity Fee payments if  there  is  a  force
majeure event (e.g., war, nationalization, etc.) that affects the
operation  of  the Upper Mahiao Project and that  is  within  the
reasonable  control  of  PNOC-EDC  or  the  Government   of   the
Philippines or any agency or authority thereof. If CE Cebu  fails
to  meet certain construction milestones or the power plant fails
to  achieve  70% of its design capacity by the date that  is  120
days  after  the scheduled completion date (as that date  may  be
extended  for  force majeure and other reasons  under  the  Upper
Mahiao   ECA),  the  Upper  Mahiao  Project  may,  under  certain
circumstances,  be deemed "abandoned," in which  case  the  Upper
Mahiao  Project  must  be transferred to  PNOC-EDC  at  no  cost,
subject to any liens existing thereon.

      PNOC-EDC is obligated to purchase CE Cebu's interest in the
facility  under  certain  circumstances, including  (i)  extended
outages  resulting from the failure of PNOC-EDC  to  provide  the
required  geothermal  fluid,  (ii) certain  material  changes  in
policies or laws which adversely affect CE Cebu's interest in the
project, (iii) transmission failure, (iv) failure of PNOC-EDC  to
make  timely payments of amounts due under the Upper Mahiao  ECA,
(v)  privatization  of PNOC-EDC or NPC, and  (vi)  certain  other
events. Prior to completion of the Upper Mahiao Project, the buy-
out price will be equal to all costs incurred through the date of
the  buy-out,  including all Upper Mahiao Project debt,  plus  an
additional rate of return on equity of ten percent per annum.  In
a  post-completion  buy-out, the price will be  the  net  present
value  (at a discount rate based on the last published Commercial
Interest   Reference  Rate  of  the  Organization  for   Economic
Cooperation  and  Development) of the total remaining  amount  of
Capacity Fees over the remaining term of the Upper Mahiao ECA.

     Mahanagdong.   In 1994 the Company also closed the financing
and  commenced construction of the Mahanagdong Project, a 165 net
MW  geothermal  project, which is also located on the  island  of
Leyte. The Mahanagdong Project is being built, owned and operated
by  CE  Luzon  Geothermal Power Company,  Inc.  ("CE  Luzon"),  a
Philippine  corporation  that during construction  is  indirectly
owned  50%  by the Company and 50% by PKS. Up to a 10%  financial
interest  in CE Luzon may be purchased at completion  by  another
industrial company at the option of such company. The Mahanagdong
Project  will  sell 100% of its capacity on a  similar  basis  as
described  above for the Upper Mahiao Project to PNOC-EDC,  which
will in turn sell the power to NPC for distribution to the island
of Luzon.

      Mahanagdong has a total project cost of approximately  $320
million,   including   interest  during   construction,   project
contingency  costs and a debt service reserve fund.  The  capital
structure consists of a project financing construction  and  term
loan  of approximately $240 million provided by OPIC, Ex-Im  Bank
and  a  consortium of international banks, and approximately  $80
million in equity contributions. Political risk insurance from Ex-
Im  Bank  has  been  obtained  for the  commercial  lenders.  The
Company's equity investment for the Mahanagdong Project  will  be
approximately $40 million. Subject to the pledge of  the  project
company's  stock  to the lenders, the Company  has  arranged  for
political  risk insurance on its equity investment through  OPIC.
The financing is collateralized by all the assets of the project.

     The Mahanagdong Project is being constructed by a consortium
(the "EPC Consortium") of Kiewit Construction Group, Inc. ("KCG")
and CE Holt pursuant to fixed-price, date-certain, turnkey supply
and construction contracts (collectively, the "Mahanagdong EPC").
The  obligations of the EPC Consortium under the Mahanagdong  EPC
are  supported by a guaranty of KCG at an aggregate amount  equal
to  approximately 50% of the Mahanagdong EPC price. KCG, a wholly
owned  subsidiary  of  PKS,  is  the  lead  member  of  the   EPC
Consortium,  with  an  80%  interest. KCG  performs  construction
services for a wide range of public and private customers in  the
U.S. and internationally. Construction projects undertaken by KCG
during 1996 included transportation projects, including highways,
bridges, airports and railroads, power facilities, buildings  and
sewer  and  waste  disposal systems, and  water  supply  systems,
utility facilities, dams and reservoirs. KCG accounts for 70%  of
PKS's revenues, contributing over $3 billion in revenues in 1996.
KCG has an extensive background in power plant construction.

     CE Holt is providing design and engineering services for the
EPC  Consortium,  and  holds  a 20%  interest.  The  Company  has
provided   a  guaranty  of  CE  Holt's  obligations   under   the
Mahanagdong EPC Contract.

      The  terms  of an energy conversion agreement, executed  on
September  18,  1993 (the "Mahanagdong ECA"),  are  substantially
similar  to  those of the Upper Mahiao ECA. The  Mahanagdong  ECA
provides for an approximately three-year construction period  and
a  ten-year  cooperation period. At the end  of  the  cooperation
period, the facility will be transferred to PNOC-EDC at no  cost.
All  of  PNOC-EDC's  obligations under the  Mahanagdong  ECA  are
supported  by  the  Government  of  the  Philippines  through   a
performance  undertaking. The capacity fees are  expected  to  be
approximately 97% of total revenues at the design capacity levels
and  the energy fees are expected to be approximately 3% of  such
total revenues.

      Malitbog.   In  1994, the Company closed the financing  and
commenced  construction of the Malitbog Project,  a  216  net  MW
geothermal project, to be constructed in two phases,  72  net  MW
(1996) and 144 net MW (1997) also located on the island of Leyte.
The  Malitbog  Project  is being built, and  will  be  owned  and
operated   by  Visayas  Geothermal  Power  Company  ("VGPC"),   a
Philippine  general partnership that is wholly owned, indirectly,
by  the  Company.  Unit  I of the Malitbog facility  was  "deemed
complete"  by  PNOC-EDC  as  of  July  25,  1996,  meaning   that
construction  of the first 72 net MW unit was completed  on  time
but the required transmission line was not completed and provided
to  VGPC. During deemed completion, PNOC-EDC is required to  pay,
and  has  in fact been paying (with respect to Unit I  which  has
been  deemed completed), all capacity fees under the take or  pay
provisions of the contract. VGPC is selling 100% of its  capacity
on  substantially the same basis as described above for the Upper
Mahiao Project to PNOC-EDC, which will in turn sell the power  to
NPC.

       The   Malitbog  Project  has  a  total  project  cost   of
approximately    $280   million,   including   interest    during
construction  and  project contingency  costs.  A  consortium  of
international  banks  and  OPIC have provided  a  total  of  $210
million  of  construction  and term  loan  facilities,  the  $135
million  international  bank portion of  which  is  supported  by
political   risk  insurance  from  OPIC.  The  Company's   equity
contribution  to  VGPC  was  $70 million.  The  Company's  equity
participation is covered by political risk insurance from OPIC.

      Units  II  and  III  of  the  Malitbog  Project  are  being
constructed  by Sumitomo Corporation ("Sumitomo") pursuant  to  a
fixed-price,   date-certain,  turnkey  supply  and   construction
contract  (the  "Malitbog EPC"). The Malitbog EPC  provides  that
certain  liquidated damages will be paid by Sumitomo for  failure
to  meet  certain scheduled test dates, including the payment  of
any  liquidated damages or penalties required to be paid by  VGPC
to  PNOC-EDC  under  an energy conversion agreement  executed  on
September  10, 1993 (the "Malitbog ECA"), subject to  limitations
on  the  total amount of liquidated damages payable by  Sumitomo.
The  Malitbog  EPC  also  provides for  the  payment  of  certain
liquidated damages on a per unit basis if upon completion of  the
facility, tests do not demonstrate such unit's ability to operate
at  a net generating capacity of at least 74.1 MW. Pursuant to  a
reimbursement undertaking, Magma has agreed to reimburse Sumitomo
for  draws, if any, by PNOC-EDC on the construction bond provided
by Sumitomo on behalf of Magma in excess of the liquidated damage
amounts provided in the Malitbog EPC.

      Sumitomo  is  one of the principal trading  and  investment
companies in Japan, and has built power plants around the  world,
often on a turnkey basis. As of February 6, 1996, Sumitomo had  a
credit  rating  of  "Aaa3" from Moody's Investors  Service,  Inc.
("Moody's").  The  Malitbog  EPC  requires  Sumitomo  to  provide
engineering,  procurement,  construction,  start-up  and  testing
services with respect to the facility.

      Commercial  operation of Units II and III are scheduled  to
commence  prior to July 25, 1997, subject to extension  upon  the
occurrence  of  certain  events (each such  date,  a  "Guaranteed
Completion  Date"). VGPC will be subject to certain penalties  if
any  generating unit does not achieve commercial operation by the
applicable Guaranteed Completion Date, and PNOC-EDC may,  in  its
sole  discretion,  terminate the Malitbog ECA if  any  generating
unit does not achieve commercial operation within 90 days of  the
applicable Guaranteed Completion Date. Pursuant to the  terms  of
the  consent agreement (the "PNOC-EDC Consent Agreement") entered
into by PNOC-EDC and VGPC, among others, PNOC-EDC has agreed that
it  will not so terminate the Malitbog ECA without providing  the
lenders and OPIC an additional 90 days within which to cure  such
abandonment.  If  the  lenders and OPIC are proceeding  with  due
diligence and in good faith to cure such abandonment, such period
may be extended for an additional 90 days with PNOC-EDC's consent
(which shall not be unreasonably withheld). In the event of  such
a  termination,  VGPC will transfer all of its right,  title  and
interest in the Malitbog Project to PNOC-EDC upon payment by PNOC-
EDC of the buy-out price for each generating unit that is not  so
delayed, but without compensation for any generating unit that is
so delayed.

     The Malitbog Project is located on land provided by PNOC-EDC
at  no cost. The electrical energy produced by the facility  will
be  sold to PNOC-EDC on a take-or-pay basis. Specifically,  PNOC-
EDC  is  obligated to make payments (the "Capacity Payments")  to
VGPC  based upon the available capacity of the Malitbog  Project.
The Capacity Payments equal approximately 100% of total revenues.
The  Capacity  Payments will be payable so long as  the  Malitbog
Project is available to produce electricity, even if the Malitbog
Project  is  not operating due to scheduled maintenance,  because
PNOC-EDC  fails  to  supply  steam to  the  Malitbog  Project  as
required  or  because  NPC  is unable (or  unwilling)  to  accept
delivery  of electricity from the Malitbog Project. In  addition,
PNOC-EDC must continue to make the Capacity Payments if there  is
a  force  majeure event (e.g., war, nationalization,  etc.)  that
affects the operation of the Malitbog Project and that is  within
the  reasonable  control of PNOC-EDC or  the  Government  of  the
Philippines  or  any  agency or authority thereof.  The  Capacity
Payments   are  designed  to  cover,  under  expected   operating
conditions,  the  Malitbog  Project's operating  and  maintenance
expenses  and  VGPC's  debt service and to provide  a  return  on
investment to the partners in VGPC. A substantial majority of the
Capacity Payments are required to be made by PNOC-EDC in dollars.
The portion of Capacity Payments payable by PNOC-EDC in pesos  is
expected  to vary over the term of the Malitbog ECA from  10%  of
VGPC's revenues in the early years of the Cooperation Period  (as
defined  below)  to  23% of VGPC's revenues at  the  end  of  the
Cooperation Period. Payments made in pesos will generally be made
to  a  peso-denominated account and will be  used  to  pay  peso-
denominated  operation and maintenance expenses with  respect  to
the Malitbog Project and Philippine withholding taxes, if any, on
the  Malitbog  Project's  debt service.  The  Government  of  the
Philippines  has  entered  into  a performance  undertaking  (the
"Performance Undertaking"), which provides that all of PNOC-EDC's
obligations pursuant to the Malitbog ECA carry the full faith and
credit of, and are affirmed and guaranteed by, the Government  of
the Philippines.

      PNOC-EDC  is obligated to purchase VGPC's interest  in  the
facility  under  certain  circumstances,  including  (i)  certain
material  changes  in  policies or laws  which  adversely  affect
VGPC's  interest in the project, (ii) any event of force  majeure
which  delays performance by more than 90 days and (iii)  certain
other  events. Prior to completion of the Malitbog  Project,  the
buy-out  price  generally will be equal  to  100%  of  all  costs
incurred  through  the date of the buy-out. In a  post-completion
buy-out,  the price will be the net present value of the  capital
cost recovery fees that would have been due for the remainder  of
the Cooperation Period with respect to such generating unit(s).

      The  Malitbog ECA cooperation period will expire ten  years
after the date of commencement of commercial operation of unit 3.
At  the  end  of  the cooperation period, the  facility  will  be
transferred to PNOC-EDC at no cost, on an "as is" basis.  All  of
PNOC-EDC's  obligations under the Malitbog ECA are  supported  by
the   Government  of  the  Philippines  through   a   performance
undertaking.  The  capacity fees are 100% of total  revenues  and
there is no energy fee.

      Casecnan.    In  November  1995,  the  Company  closed  the
financing  and commenced construction of the Casecnan Project,  a
combined irrigation and 150 net MW hydroelectric power generation
project  (the "Casecnan Project") located in the central part  of
the  island  of  Luzon  in the Republic of the  Philippines.  The
Casecnan  Project will consist generally of diversion  structures
in  the  Casecnan and Denip Rivers that will divert water into  a
tunnel  of approximately 23 kilometers. The tunnel will  transfer
the water from the Casecnan and Denip Rivers into the Pantabangan
Reservoir  for  irrigation and hydroelectric use in  the  Central
Luzon  area. An underground powerhouse located at the end of  the
water  tunnel and before the Pantabangan Reservoir will  house  a
power plant consisting of approximately 150 MW of newly installed
rated  electrical  capacity. A tailrace tunnel  of  approximately
three kilometers will deliver water from the water tunnel and the
new powerhouse to the Pantabangan Reservoir, providing additional
water  for  irrigation  and increasing the  potential  electrical
generation at two downstream existing hydroelectric facilities of
the NPC.

      CE  Casecnan  Water and Energy Company, Inc., a  Philippine
corporation  ("CE Casecnan") which is presently indirectly  owned
as  to  approximately  35%  of its  equity  by  the  Company  and
approximately  35%  indirectly owned by PKS,  is  developing  the
Casecnan Project under the terms of the Project Agreement between
CE  Casecnan and the National Irrigation Administration  ("NIA").
Under  the  Project Agreement, CE Casecnan will develop,  finance
and  construct  the Casecnan Project over an estimated  four-year
construction period, and thereafter own and operate the  Casecnan
Project  for  20  years  (the "Cooperation Period").  During  the
Cooperation Period, NIA is obligated to accept all deliveries  of
water  and  energy,  and  so  long as  the  Casecnan  Project  is
physically capable of operating and delivering in accordance with
agreed levels set forth in the Project Agreement, NIA will pay CE
Casecnan  a  guaranteed  fee for the  delivery  of  water  and  a
guaranteed fee for the delivery of electricity, regardless of the
amount  of  water or electricity actually delivered. In addition,
NIA  will pay a fee for all electricity delivered in excess of  a
threshold  amount  up to a specified amount. NIA  will  sell  the
electric  energy it purchases to NPC, although NIA's  obligations
to  CE Casecnan under the Project Agreement are not dependent  on
NPC's  purchase of the electricity from NIA. All fees to be  paid
by NIA to CE Casecnan are payable in U.S. dollars. The guaranteed
fees for the delivery of water and energy are expected to provide
approximately 70% of CE Casecnan's revenues.

      The  Project Agreement provides for additional compensation
to  CE  Casecnan upon the occurrence of certain events, including
increases  in Philippine taxes and adverse changes in  Philippine
law.  Upon  the occurrence and during the continuance of  certain
force majeure events, including those associated with Philippines
political  action,  NIA  may be obligated  to  buy  the  Casecnan
Project  from CE Casecnan at a buy out price expected  to  be  in
excess  of  the aggregate principal amount of the outstanding  CE
Casecnan  debt  securities,  together  with  accrued  but  unpaid
interest.  At  the  end of the Cooperation Period,  the  Casecnan
Project  will  be  transferred to NIA and NPC for  no  additional
consideration on an "as is" basis.

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

      The  Casecnan Project is being constructed on a  joint  and
several  basis  by  Hanbo  Corporation and  Hanbo  Engineering  &
Construction  Co. Ltd. (formerly known as You One  Engineering  &
Construction  Co., Ltd., and herein referred to as "HECC"),  both
of  which  are South Korean corporations, pursuant  to  a  fixed-
price,  date-certain, turnkey construction contract (the "Turnkey
Construction  Contract"). Hanbo Corporation and  HECC  (sometimes
collectively  referred to as the "Contractor") are  under  common
ownership   control.  Hanbo  Corporation  is   an   international
construction company. HECC, which recently emerged from a  court-
administered  receivership, is a contractor with  over  25  years
experience in tunnel construction, using both the drill-and-blast
and tunnel boring machine ("TBM") methods.

      The Contractor's obligations under the Turnkey Construction
Contract  are  guaranteed by Hanbo Iron  &  Steel  Company,  Ltd.
("Hanbo Steel"), a large South Korean steel company. In addition,
the  Contractor's  obligations  under  the  Turnkey  Construction
Contract  are  secured by an unconditional,  irrevocable  standby
letter  of  credit  issued by Korea First  Bank  ("KFB")  in  the
approximate  amount  of  $118 million.  The  total  cost  of  the
Casecnan  Project,  including development, construction,  testing
and startup, is estimated to be approximately $495 million.

      In  late  January 1997, the Company was advised that  Hanbo
Corporation  and  Hanbo  Steel  had  each  filed  to  seek  court
receivership protection in Korea. At the present time, all of the
construction  work on the Casecnan Project is being performed  by
the  second contractor which is party to the Turnkey Construction
Contract, HECC. Although HECC, Hanbo Corporation and Hanbo  Steel
are  under  common  ownership control, HECC  has  not  filed  for
receivership  protection and is believed to be solvent.  However,
no   assurances  can  be  given  that  HECC  will  not  file  for
receivership  due to the foregoing developments or that  it  will
remain  solvent  and able to perform fully its obligations  under
the Turnkey Construction Contract.

      The  work on the Casecnan Project, which commenced in 1995,
is  presently  continuing on schedule and within the  budget.  CE
Casecnan  is  presently  reviewing its  rights,  obligations  and
potential   remedies  in  respect  of  the  recent   developments
regarding  the co-Contractor and the guarantor and  is  presently
unable   to  speculate  as  to  the  ultimate  effect   of   such
developments  on CE Casecnan. However, CE Casecnan  has  recently
received confirmation from HECC that it intends to fully  perform
its  obligations  under  the  Turnkey Construction  Contract  and
complete the Casecnan Project on schedule and within the  budget.
Additionally,  it  has  been  reported  that  the  South   Korean
government has informed the Philippine government that the  South
Korean government will take appropriate actions to support HECC's
completion of the Casecnan Project.

      KFB  has recently reconfirmed to CE Casecnan that  it  will
honor its obligations under the Casecnan Project letter of credit
and also has stated its support for the successful completion  of
the  Casecnan  Project.  However, Moody's Investors  Service  has
recently  issued a warning for a possible ratings  downgrade  for
KFB   because   of  the  possible  impact  of  the  Hanbo   Steel
receivership  on  the substantial loans KFB  previously  made  to
Hanbo   Steel.  In  a  related  development,  the  South   Korean
government  has  recently announced that it  would  provide  some
funding  to  assist Hanbo Steel's creditor banks (including  KFB)
and its subcontractors.

      CE Casecnan financed a portion of the costs of the Casecnan
Project through the issuance of $125,000,000 of its 11.45% Senior
Secured  Series A Notes due 2005 and $171,500,000 of  its  11.95%
Senior  Secured Series B Notes due 2010 pursuant to an  indenture
dated  November  27,  1995, as amended  to  date  (the  "Casecnan
Indenture"). Although no default has occurred under the  Casecnan
Indenture  as  a  result of the announced receivership  of  Hanbo
Corporation,  CE  Casecnan will continue to closely  monitor  the
Hanbo  group and KFB developments and project construction status
and develop appropriate contingency plans.

      If  HECC were to materially fail to perform its obligations
under  the Turnkey Construction Contract and if KFB were to  fail
to  honor  its obligations under the Casecnan letter  of  credit,
such actions could have a material adverse effect on the Casecnan
Project  and  CE  Casecnan.  However, based  on  the  information
presently available to it, CE Casecnan does not presently  expect
that either such event will occur.

      Indonesia.  Indonesia, which has the world's fourth largest
population,  has experienced rapid growth in electricity  demand.
The  Company  believes that annual load growth has  exceeded  13%
since   1980.  Furthermore,  the  Company  believes  that   rapid
expansion   in  industrial  growth  has  created  a  backlog   of
unconnected industrial users in excess of 4,000 MW. In its  sixth
five-year  plan,  the Indonesian government has  called  for  the
addition of 12,000 MW of additional generating capacity by  1999.
The long range plan calls for an additional 15,000 MW to be added
by  the  year 2004. The plans call for approximately 75% of  this
capacity  to  be  added by independent power producers.  Although
Indonesia  is  a  member of OPEC and is also the world's  largest
exporter of liquefied natural gas, the Indonesian government  has
announced  that it wishes to maintain sufficient amounts  of  oil
for  export, which will require a shift to coal fired  generation
and the use of other energy sources, such as geothermal.

      It  is  estimated that Indonesia has sufficient  geothermal
steam  potential to generate 16,000 MW, centered in the Java  and
Sumatra  areas  (the two most populous of the 13,000  islands  in
Indonesia).  To  date, less than 150 MW of geothermal  facilities
have  been commissioned, as the government of Indonesia  was  not
encouraging the development of geothermal energy.

       The  Indonesian  state-owned  utility  has  recently  been
converted  to  a  limited liability company, P.T.  PLN  (Persero)
("PLN"),  as  a first step toward the privatization  of  its  two
largest   generating   subsidiaries.  The   main   objective   of
Indonesia's  electric  energy  policy  has  been  to   secure   a
continuity  of  supply at reasonable rates for  households  (more
than  50%  of which have been reported to have no power)  and  to
minimize  the  utilization of hydrocarbons. Rural electrification
will remain an important component of the energy policy as PLN is
targeting the addition of 2 million customers a year.

     Indonesia is rated "Baa3" by Moody's and "BBB" by Standard &
Poor's Ratings Group ("S&P"). The Company believes that Indonesia
represents an attractive development opportunity, as it  combines
growing   power   needs  with  ample  geothermal  resources   and
creditworthy contract parties.

      Dieng  Unit I.   On December 2, 1994, a subsidiary  of  the
Company, Himpurna California Energy Ltd. ("HCE") executed a joint
operation contract (the "Dieng JOC") for the development  of  the
geothermal  steam  field and geothermal power facilities  at  the
Dieng  geothermal  field,  located in Central  Java  (the  "Dieng
Project") with Perusahaan Pertambangan Minyak Dan Gas Bumi Negara
("Pertamina"), the Indonesian national oil company, and  executed
a "take-or-pay" energy sales contract (the "Dieng ESC") with both
Pertamina and PLN, the Indonesian national electric utility.  HCE
was  formed pursuant to a joint development agreement  with  P.T.
Himpurna  Enersindo  Abadi ("P.T. HEA"), its Indonesian  partner,
which  is  a subsidiary of Himpurna, an association of Indonesian
military  veterans, whereby the Company and P.T. HEA have  agreed
to  work  together  on an exclusive basis to  develop  the  Dieng
Project  (the "Dieng Joint Venture"). The Dieng Joint Venture  is
structured   with   subsidiaries  of  the  Company   holding   an
approximate  47%  interest  (including  certain  assignments   of
dividend  rights representing an economic interest  of  2%),  and
subsidiaries   of  PKS  holding  an  approximate   47%   interest
(including certain assignments of dividend rights representing an
economic  interest of 2%) and P.T. HEA holding a 6%  interest  in
the Dieng Project. The construction contractor for the Dieng Unit
I  project, a joint venture of PKS and CE Holt, is on schedule to
complete  the  Unit I plant and commence commercial operation  by
the fourth quarter of 1997. Major activities since the notice  to
proceed  was issued to the contractor in March 1996 have  focused
on  site civil work, including site preparation, foundation work,
and  access  road  construction. The turbine/generator  purchased
from  the  Italian national utility, ENEL, has been delivered  to
the site.

       All   government  approvals  necessary  for  closing  were
received,  including  a  support  letter  from  the  Republic  of
Indonesia, an off-shore loan board (Decree 39) approval, consents
to  assignment from the Republic of Indonesia, PLN and Pertamina,
and  all required environmental approvals. Financial closing  and
first disbursement of construction loan funds occurred on October
3, 1996.

      Pursuant to the Dieng JOC and ESC, Pertamina has granted to
HCE  the  geothermal  field and the wells  and  other  facilities
presently  located thereon and HCE will build,  own  and  operate
power  production units with an aggregate capacity of up  to  400
MW.  HCE  will  accept  the  field operation  responsibility  for
developing and supplying the geothermal steam and fluids required
to  operate the plant. The Dieng JOC is structured as a build own
transfer  agreement  and  will expire (subject  to  extension  by
mutual agreement) on the date which is the later of (i) 42  years
following  effectiveness  of the Dieng  JOC  and  (ii)  30  years
following  the  date of commencement of commercial generation  of
the  final  unit completed. Upon the expiration of  the  proposed
Dieng JOC, all facilities will be transferred to Pertamina at  no
cost.  HCE  is  required to pay Pertamina a production  allowance
equal  to  three percent of HCE's net operating income  from  the
Dieng  Project,  plus a further amount based upon the  negotiated
value of existing Pertamina geothermal production facilities that
the Company expects will be made available by Pertamina.

      Pursuant to the Dieng ESC, PLN agreed to purchase  and  pay
for all of the Project's capacity and energy output on a "take or
pay" basis regardless of PLN's ability to accept such energy made
available from the Dieng Project for a term equal to that of  the
Dieng  JOC. The price paid for electricity includes a base energy
price per kWh multiplied by the number of kWhs the plants deliver
or  are  "capable  of delivering," whichever is  greater.  Energy
price payments are also subject to adjustment for inflation.  PLN
will  also  pay  a capacity payment based on plant capacity.  All
such payments are payable in U.S. dollars.

      HCE  began well testing in the fourth quarter of  1995  and
issued a notice to proceed for the construction and supply of  an
initial  55 net MW unit ("Dieng Unit I") in the first quarter  of
1996.  PT Kiewit/Holt Indonesia, a consortium consisting  of  KCG
and  CE  Holt, will construct Dieng Unit I pursuant  to  a  fixed
price, date certain, turnkey construction contract ("Construction
Contract").  Affiliates  of KCG and  CE  Holt  will  provide  the
engineered  supply with respect to Dieng Unit  I  pursuant  to  a
fixed  price,  date  certain, turnkey  supply  contract  ("Supply
Contract").  The  Construction Contract and Supply  Contract  are
sometimes referred to herein as the "Dieng EPC" and KCG, CE  Holt
and  their  affiliates  party to the  Construction  Contract  and
Supply  Contract are sometimes referred to herein,  collectively,
as   the  "Construction  Consortium."  The  obligations  of   the
Construction  Consortium  under  the  Construction   and   Supply
Contracts are supported by a guaranty of KCG and CE Holt. KCG  is
the  lead  member  of  the Construction Consortium,  with  a  60%
interest. HCE will be responsible for operating and managing  the
Dieng Project.

      Pursuant  to  the Dieng JOC and ESC, the Company  presently
intends to proceed on a modular basis with construction of  three
additional  units  to  follow  Dieng  Unit  I,  resulting  in  an
aggregate  first phase net capacity at this site of 220  MW.  The
Company estimates that the total project cost of these units will
be  approximately  $450 million. The next phase  is  expected  to
expand  the total capacity to 400 MW. The cost of the full  Dieng
Project is estimated to approximate $1 billion.

      The Dieng field has been explored domestically for over  20
years and CE Holt has been active in the area for more than  five
years.  Pertamina has drilled a total of 27 wells  to  date.  The
Company has a significant amount of data, which it believes to be
reliable  as to the production capacity of the field. However,  a
number of significant steps, both financial and operational, must
be  completed before the Dieng Project can proceed further. These
steps,  none  of  which  can be assured, include  completing  the
drilling  of  wells and the constructing of the plant  for  Dieng
Unit  I  and obtaining required regulatory permits and approvals,
completing   the  well  testing,  entering  into  a  construction
agreement  and  other project contracts, and arranging  financing
for the other units at Dieng.

     United Kingdom.  In the United Kingdom, a Northern
subsidiary Northern Electric Generation Limited ("Northern
Generation") focuses on electricity generation, primarily through
its ownership in Teesside (described herein).  Northern
Generation also operates a 5 MW diesel power generating plant
located in Northallerton, England in which the Company has a 3 MW
net ownership interest and operates 47 small-scale combined heat
and power facilities.

      Teesside.   Teesside  Power Limited ("Teesside")  owns  and
operates  an  1,875 MW combined cycle gas-fired  power  plant  at
Wilton. Northern owns a 15.4% stockholding in Teesside, but  does
not  operate  the plant. Northern purchases 400 MW of electricity
from Teesside under a 15-year power purchase agreement.

     Viking.   Viking Power Limited ("Viking") is a company owned
50% by Northern and 50% by Rolls-Royce Power Ventures. The Viking
project  is  constructing a 50 MW gas-fired power plant  at  Seal
Sands  on  Teesside. The project will utilize an  aero-derivative
Rolls-Royce Trent Engine and it will be embedded on the  Northern
distribution network. Construction has commenced on the plant and
the project is being managed and, upon commercial operation, will
be operated by Northern and its partner.

Projects in Development

       The   following  is  a  summary  description  of   certain
information  concerning  the Company's international  development
projects. Since these projects are still in development there can
be  no assurance that this information will not change materially
over   time.  In  addition,  there  can  be  no  assurance   that
development  efforts on any particular project, or the  Company's
efforts generally, will be successful.

Philippines

      Alto  Peak.  The Alto Peak Project is a smaller  geothermal
project  in  the same general area of Leyte as the Upper  Mahiao,
Mahanagdong  and Malitbog Projects. A subsidiary of  the  Company
and  PNOC-EDC  have  executed  a  70  net  MW  Energy  Conversion
Agreement,  dated May 7, 1994. The general terms  and  conditions
are  similar to the Malitbog ECA. However, the plant  design  has
not  been initiated because PNOC-EDC has not finalized the  steam
conditions  (pressure,  composition and pH).  PNOC-EDC  is  still
drilling and testing the geothermal wells that will supply  steam
to  such project. Consequently, the ECA has been extended and the
Company  has  not commenced financing arrangements for  the  Alto
Peak Project.

Indonesia

      Dieng.    Pursuant  to the Dieng JOC and ESC,  the  Company
intends  to  proceed  on  a modular basis  with  construction  of
additional  units  to  follow  Dieng  Unit  I,  resulting  in  an
aggregate  first phase net capacity at this site of 220  MW.  The
Company estimates that the total project cost of these units will
be  approximately  $450 million. The next phase  is  expected  to
expand  the total capacity to 400 MW. The cost of the full  Dieng
Project   is  estimated  to  approximate  $1  billion.  See   the
discussion set forth above concerning construction of Dieng  Unit
I for a more complete description of the Dieng Project.

      Patuha.   The Company is also developing a geothermal power
plant  in  the  Patuha geothermal field in Java,  Indonesia  (the
"Patuha  Project"). Subsidiaries of the Company will have  a  44%
interest and subsidiaries of PKS will have a 44% interest in  the
Patuha Project.

      On  December  2, 1994, the project company  developing  the
Patuha Project, Patuha Power, Ltd. ("Patuha Power") executed both
a  joint operation contract and an energy sales contract, each of
which  contains  terms substantially similar to  those  described
above for the Dieng Project. Patuha Power intends to proceed on a
modular  basis  similar to the Dieng Project, with  an  aggregate
capacity  of up to 400 MW. The Company estimates that  the  total
cost  will  be approximately $1 billion. The Company  began  well
testing and exploration in the fourth quarter of 1995 and expects
to commence construction of the first unit in 1997.

       The  Patuha  Project  remains  subject  to  a  number   of
significant uncertainties, as described above in connection  with
the  Dieng Project, and there can be no assurance that the Patuha
Project will proceed or reach commercial operation.

      Bali.    The  Company and PT Panutan Group,  an  Indonesian
consortium of energy, oil, gas and mining companies, have  formed
a joint venture to pursue the development of geothermal resources
in Bali (the "Bali Project"). The PT Panutan Group is entitled to
contribute up to 40% of the total equity and obtain up to 40%  of
the  net  profit of the Bali Project. On November 17,  1995,  the
project  company  developing the Bali Project, Bali  Energy  Ltd.
("Bali Energy"), executed both a joint operation contract and  an
energy  sales  contract, each of which currently  contains  terms
substantially  similar to those described  above  for  the  Dieng
Project.  Bali  Energy  intends to proceed  on  a  modular  basis
similar to the Dieng Project, with an aggregate capacity of up to
400  MW.  The Company estimates that the total cost of  the  Bali
Project  will be approximately $1 billion. The Company  presently
intends  to begin well testing and exploration in early 1997  and
expects to commence construction of the first unit in 1998.

      The  Company presently intends to develop the Bali  Project
and  other  possible  projects  in Indonesia  using  a  structure
similar to that contemplated for the Dieng Project.

      The Bali Project remains subject to a number of significant
uncertainties,  as  described above for the  Dieng  Project,  and
there  can be no assurance that the Bali Project will proceed  or
reach commercial operation.

  International Electricity Distribution and Supply Operations

United Kingdom

      Great Britain has two separate but connected markets,  each
with  a  different  commercial framework. In  England  and  Wales
electricity is produced by generators, the largest of  which  are
National  Power, PowerGen and Nuclear Electric, a  subsidiary  of
the privatized British Energy. Electricity is transmitted through
the  national grid transmission system by NGC and distributed  by
the  twelve  RECs  in  their respective  authorized  areas.  Most
customers currently are supplied with electricity by their  local
REC,  although  there  are other suppliers  holding  second  tier
supply  licenses, including other generators and  RECs,  who  can
compete to supply larger customers in that REC's authorized area.

      In  Scotland there are two vertically integrated companies,
Scottish Power and Hydro-Electric, each generating, transmitting,
distributing  and  supplying electricity within their  respective
Authorized  Areas  as  well as competing  to  supply  electricity
elsewhere.  Scottish  Nuclear,  another  subsidiary  of   British
Energy, sells all the electricity it generates to Scottish  Power
and Hydro-Electric under the Nuclear Energy Agreement.

      The  interconnection between the two transmission  systems,
owned  by  Scottish  Power  and NGC, is capable  of  transferring
electricity between Scotland and England and Wales. There is also
an  interconnection with France, owned by Electricite  de  France
and NGC, through which electricity can be transferred between the
transmission systems of France and England and Wales.

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

     There is no equivalent to the Pool in Scotland, but Scottish
Power and Hydro-Electric are obligated by their licenses to offer
electricity  for  sale to second tier suppliers.  They  are  also
required to provide access to their transmission and distribution
systems on a non-discriminatory basis to competing suppliers  and
generators.

      The  industry  structure described above  became  effective
April  1990. At the same time, a licensing regime was  introduced
for  the  electricity industry both in England and Wales  and  in
Scotland.  The Regulator (defined herein) was first appointed  in
1989.

      The  RECs, which at that time collectively owned NGG, NGC's
holding company, were privatized in December 1990. National Power
and  PowerGen were privatized in March 1991 (with the balance  of
the  United Kingdom's stock ownership being sold in March  1995),
Scottish  Power and Hydro-Electric were privatized in  June  1991
and British Energy was privatized in July 1996. NGG was listed on
the  London Stock Exchange in December 1995. Since the summer  of
1995, a majority of RECs have been acquired by other companies. A
majority  ownership  interest in one of the RECs,  Northern,  was
acquired by CE Electric on December 24, 1996.

      In 1990, the vast majority of generating capacity was owned
by  three  generators. However, since that  time  competition  in
generation has increased as RECs and other new entrant generators
have   constructed  new  plants  and  as  imports   through   the
interconnections  with  Scotland  and  France  have   grown.   In
addition,  pursuant  to  undertakings  given  to  the  Regulator,
National  Power  and PowerGen have disposed of  an  aggregate  of
6,000  MW  of plants to Eastern Group plc (a REC holding  company
which was acquired by Hanson plc).

     Competition in supply also has been progressively introduced
in  England  and Wales and in Scotland. The RECs in  England  and
Wales,  and  Scottish Power and Hydro-Electric in  Scotland,  are
subject to competition from second tier suppliers for the  supply
of electricity to larger customers in their respective authorized
areas.  Under  the  current  licensing  regime,  all  electricity
customers in the United Kingdom, including residential customers,
will be able to choose their electricity supplier after March 31,
1998.

      All  the  RECs  are subject to an obligation  to  obtain  a
specified  amount  of  generating capacity from  non-fossil  fuel
sources  (the "NFFOs"). Because electricity generated  from  non-
fossil  fuel  plants is generally more expensive than electricity
from  fossil fuel plants, a levy system (the "Fossil Fuel  Levy")
has  been  instituted  to recover the extra costs  involved.  The
Fossil Fuel Levy is charged at a fixed percentage of the value of
sales  of  electricity  (subject to certain  exemptions)  by  all
licensed electricity suppliers. The Regulator sets the amount  of
the Fossil Fuel Levy annually. The original Fossil Fuel Levy rate
was  10%  of  the  value of sales of electricity  generated  from
fossil fuel sources. The rate has since been reduced to 3.7%  and
will be reduced again to 2.25% effective April 1, 1997.

Distribution of Electricity

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

     The prices for distribution to most customers are controlled
by  a  prescribed formula that limits increases (and may  require
decreases) based on the rate of inflation in the United  Kingdom.
Prices  for  distribution to customers taking their  supplies  at
extra  high  voltages are not directly controlled. The  Regulator
reviewed the initial price formula in 1994 and introduced changes
that  initially caused prices to be approximately  17%  lower  in
Northern's fiscal year ended March 31, 1996 than they would  have
been  had  the initial formula continued unchanged. The Regulator
also  limited price increases in future years, and in  July  1995
the   Regulator  limited  price  increases  further.   Currently,
increases  will  be  limited  to three  percentage  points  below
inflation  through  March 31, 2000. Northern estimates  that  the
combined  effect  of the two reviews will be  to  reduce  pre-tax
income by approximately pounds sterling 95 million (based on 1995-
96 prices) for the four year period ending March 31, 2000.

      Most  of  Northern's distribution customers  are  Franchise
Supply  Customers. This customer group consists predominantly  of
residential and small commercial customers which are believed  by
Northern to constitute a stable customer base. Northern's fastest
growing  category of distribution customers, in  terms  of  units
distributed and revenues, is commercial customers (as  contrasted
with  industrial  customers), most of which are Franchise  Supply
Customers.  Northern also distributes electricity  to  industrial
concerns   in   its  Authorized  Area.  Northern's   20   largest
distribution  customers  in  its Authorized  Area  accounted  for
approximately 18% of total electricity distributed by Northern in
Northern's  fiscal year ended March 31, 1996 in  terms  of  units
distributed,  with  no  single customer  exceeding  4%  of  total
electricity distributed.

       Electricity  is  transported  across  the  national   grid
transmission  system  to  grid supply  points  within  Northern's
distribution  network, where it is transformed  by  Northern  and
enters  Northern's  distribution  system.  Electricity  is   also
transported to national grid supply points located in neighboring
RECs'   authorized  areas,  which  are  connected  to  Northern's
distribution system by overhead lines and underground cables.

      At  March  31,  1996,  Northern's electricity  distribution
network  (excluding  service connections to  consumers)  included
approximately   17,000   kilometers   of   overhead   lines   and
approximately   26,000   kilometers   of   underground    cables.
Substantially all substations are owned in freehold, and most  of
the  balance are held on leases which will not expire  within  10
years.

      In  addition to the circuits referred to above,  Northern's
distribution   facilities  also  include   approximately   26,000
transformers and approximately 23,000 substations. Electricity is
received  by customers at various voltages depending  upon  their
requirements.  In providing service connections to customers  and
to  street lighting, traffic lights and other installations  from
its   network,  Northern  uses  lengths  of  overhead  lines  and
underground cables in addition to those referred to above.

      Operations and control of Northern's distribution system is
continuously monitored and coordinated from two control  centers.
A  telecontrol  system  has been implemented  to  provide  remote
information gathering and to provide remote operation of selected
switchgear.

      Each  of the RECs is required to offer terms for connection
to  its  distribution  system  to any  person,  for  use  of  its
distribution  system to any authorized electricity  operator  and
for  the provision of top-up and stand-by supplies to any person.
In  providing  use of its distribution system,  a  REC  must  not
discriminate  between its own supply business  and  that  of  any
other  authorized electricity operator, or between those of other
authorized  electricity  operators; nor may  its  charges  differ
except where justified by differences in cost. Similar principles
apply  to  the  provision  of top-up  and  stand-by  supplies  of
electricity,  and  in  the  carrying  out  of  connection  works.
Disputes  over  the  terms of offers may  be  determined  by  the
Regulator.

     Most revenue of the distribution business is controlled by a
formula  where the permitted maximum average price  per  unit  is
increased  (or  decreased) each year by RPI-XD (the "Distribution
Price Control Formula"). RPI reflects the average of the 12 month
inflation  rates  recorded  for the  previous  July  to  December
period.  The  Distribution Price Control Formula, XD  factor,  is
established by the Regulator following review and is  set  at  3%
from  April 1, 1997. This formula determines the maximum  average
price  per unit of electricity distributed (in pence per kilowatt
hour)  which  a  REC  is  entitled to charge.  This  price,  when
multiplied by the expected number of units to be distributed  and
customer  numbers, determines the expected distribution  revenues
of  the REC for the relevant year. The Distribution Price Control
Formula permits RECs to partially retain additional revenues  due
to  increased distribution of units and a predetermined  increase
in customer numbers. The price control does not seek to constrain
the profits of a REC from year to year. It is a control on income
which  operates  independently of the  REC's  costs.  During  the
lifetime  of the price control additional cost savings  therefore
contribute directly to profit.

     On August 11, 1994, the Regulator announced the results of a
review  of  the  Distribution Price Control Formula.  A  one-time
reduction  in the permitted income from distribution  charges  of
all  the RECs was made with effect from April 1, 1995 and  ranged
from 11% to 17% (the reduction in Northern's case being 17%),  in
each  case  before  allowing  for  inflation.  In  addition,  the
Regulator  halved from 100% to 50% the weight  of  units  in  the
Distribution  Price Control Formula and allocated  the  remaining
50%  to  the number of customers. An XD of 2% was also  set.  The
stated intention of the Regulator in introducing this change  was
"to remove any artificial incentive on the companies to sell more
electricity, while retaining a general incentive for companies to
seek  out  and  meet the needs of their customers.  In  light  of
information  concerning the financial position of the  RECs  that
emerged  during the course of the unsuccessful bid  by  Trafalgar
House  plc  for  Northern, the Regulator carried  out  a  further
review  which led to further reduced distribution charges of  all
the  RECs as of April 1, 1996 in amounts ranging from 10% to  13%
(the reduction in Northern's case being 13%), in each case before
allowing for inflation, and also increased the XD to 3% effective
April 1, 1997.

      The  Distribution Price Control Formula is expected  to  be
further  reviewed, effective as of April 1, 2000. A REC may  seek
disapplication  of  its Distribution Price Control  Formula  with
effect  from that date by request to the Regulator. If  agreement
is  not reached on a new formula, the Regulator must refer it  to
the Monopolies and Mergers Commission ("MMC").

     In setting the distribution charges each year, the holder of
a  PES  license  will have to make a projection of the  permitted
maximum  charge per unit distributed in that year. The projection
will  have  to  take  account of forecasts of units  distributed,
distribution losses and the expected revenue in the current year.
Failure  to  forecast accurately may result in  over-  or  under-
charging;  this  is  taken into account  in  the  following  year
through  a correction factor in the price control formula.  If  a
REC  has  overcharged in the previous year, the  maximum  average
charge  per  unit distributed is reduced by an amount to  reflect
the  excess income received, to which is added interest.  In  the
event  of  undercharging, the Distribution Price Control  Formula
allows  the  licensee  to recover the shortfall  in  income  plus
interest.

      If,  in  any  year, the average charge per unit distributed
exceeds the permitted maximum average charge per unit distributed
by  more  than 3%, then, in the next following year, the REC  may
not  increase  distribution charges unless it has  satisfied  the
Regulator that the average charge per unit in that next following
year  is  not  likely  to  exceed the permitted  maximum  average
charge.  If, in respect of any two successive years, the  sum  of
the  amounts by which the average charge per unit distributed has
exceeded   the   permitted  maximum  average  charge   per   unit
distributed in the second of those years is more than  4%,  then,
in  the  next  following year, the REC may  be  required  by  the
Regulator  to  adjust its charges so that they  fall  within  the
maximum  permitted  average  charge.  If,  in  respect   of   two
successive years, the licensee undercharges by more than  10%  of
the  maximum average charge, the Regulator may, by directions  to
the licensee, limit the amount by which such undercharging may be
recovered.

Supply of Electricity

     Northern Electric Supply Limited ("Northern Supply") focuses
on  Northern's supply business and is responsible for  marketing,
tariff setting, contracts and customer service in connection with
the  supply  of  both  electricity  and  gas.  Northern's  supply
business  involves  the  bulk purchase of electricity,  primarily
from the Pool, and subsequent sale to individual customers. Until
March  31,  1998, each of the RECs is the exclusive  supplier  of
electricity to premises in each of their authorized areas, except
where the maximum demand of a customer is greater than 100kW. The
formula  described  below controls the  income  that  the  supply
business  may receive from franchise customers and therefore  the
profits  that  can be derived from the supply of  electricity  to
franchise  customers.  Supplies  to  other  customers   are   not
regulated since the Regulator believes that the market in  excess
of  100kW  is sufficiently competitive not to require  this.  The
current  regulations  that permit each of  the  RECs  to  be  the
exclusive supplier in each of their authorized areas will  expire
as of March 31, 1998.

     Under the terms of its PES license, Northern currently holds
the  right  to supply approximately 1.5 million Franchise  Supply
Customers  within  Northern's Authorized Area. During  Northern's
fiscal  year  ended  March 31, 1996, sales  to  Franchise  Supply
Customers represented 51% of total units supplied by Northern and
produced 63% of Northern's total supply revenue. Northern intends
to  seek to retain its market share of Franchise Supply Customers
after  March 31, 1998 by providing superior customer service  and
competitive pricing.

      In addition to competing for Non-Franchise Supply Customers
in  its Authorized Area, Northern holds a second tier license  to
compete  with the RECs and other suppliers to provide electricity
to Non-Franchise Supply Customers outside its Authorized Area.

      Northern is one of the largest suppliers in the competitive
and  open  electricity market in the United Kingdom and  supplies
customers  in  all  15  PES areas in Great Britain  and  Northern
Ireland. Northern supplies substantially more sites than  it  had
previously supplied prior to the beginning of open competition in
the  supply business in the United Kingdom. In addition, Northern
Supply  maintains a gas supply business and, at March  31,  1996,
Northern  had won gas supply contracts for more than 4,000  sites
nationally, mainly outside northeast England.

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

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

      At  present,  a  Franchise Supply  Customer  can  only  buy
electricity  from  the  PES authorized  to  supply  the  relevant
authorized  area.  Franchise Supply Customers  typically  include
domestic and small commercial and small industrial customers. Non-
Franchise Supply Customers with demand over 100kW are not limited
to  buying electricity from the local PES and can choose  to  buy
from  a second tier supplier. Such customers are typically larger
commercial, agricultural and industrial electricity users. Second
tier suppliers compete with one another and with the local PES to
supply  customers in this competitive (or "non-franchise") sector
of the market.

      Under  the current licensing regime, after March 31,  1998,
all customers, including those who are currently Franchise Supply
Customers, will be free to choose their electricity supplier.

      The supply of electricity to Franchise Supply Customers  is
subject  to  price control. The maximum permitted average  charge
per unit supplied (in pence per kilowatt hour) is controlled by a
formula whereby certain costs are passed through in full  (the  Y
term)  to  customers. The permitted income per unit  supplied  in
respect  of  the supply business' own costs and margin  increases
(or  decreases)  each year by RPI--X (the "Supply  Price  Control
Formula")  where Xs is currently 2%. RPI reflects the average  of
the  12  month inflation rates recorded for the previous July  to
December  period. The Xs factor is established by  the  Regulator
during the price control review. The Y term is a pass-through  of
certain costs which are either largely outside the control of the
REC  or  have been regulated elsewhere. It thus covers the  REC's
electricity  purchase costs, including both direct Pool  purchase
costs  and  costs of hedging, transmission charges made  by  NGC,
distribution  charges made by its own and other REC  distribution
businesses  and  the  Fossil Fuel Levy (as described  herein)  or
amounts  equivalent thereto in respect of the  purchase  of  non-
leviable  electricity which are attributable to Franchise  Supply
Customers.

      As with the Distribution Price Control Formula, there is  a
correction  factor  in the Supply Price Control  Formula  in  the
event of over-or under-charging. If a REC has overcharged in  the
previous  year, the maximum average charge per unit  supplied  is
reduced  by  an amount to reflect the excess income received,  to
which  is  added  interest. In the event of  under-charging,  the
Supply  Price Control Formula allows the licensee to recover  the
shortfall in income plus interest.

      If,  in  any  year,  the average charge per  unit  supplied
exceeds the permitted maximum average charge per unit supplied by
more  than 4%, then, in the next following year, the REC may  not
increase  supply charges to Franchise Supply Customers unless  it
has  satisfied the Regulator that the average charge per unit  in
that  next  following year is not likely to exceed the  permitted
maximum  average  charge. If, in respect of  any  two  successive
years,  the  sum of the amounts by which the average  charge  per
unit  supplied has exceeded the permitted maximum average  charge
per unit supplied in the second of those years is more than 5% of
that   permitted  maximum  average  charge,  then,  in  the  next
following  year,  the  REC may be required by  the  Regulator  to
adjust its charges so that they fall within the maximum permitted
average  charge.  If,  in respect of two  successive  years,  the
licensee  under-charges by more than 10% of the  maximum  average
charge,  the Regulator may, by directions to the licensee,  limit
the amount by which such under-charging may be recovered.

      The  initial value of Xs was set at 0 for all the  RECs  on
April  1, 1990. The Supply Price Control Formula was reviewed  by
the  Regulator with effect from April 1, 1994, when the  Xs  term
was  set  at  2% for all the RECs. This will apply to the  period
ending  March 31, 1998. On this date, the exclusive right of  the
RECs to supply Franchise Supply Customers is scheduled, under the
current  licensing  structure, to come to an  end.  However,  the
Regulator has indicated that price regulation for supply to  some
former Franchise Supply Customers is likely to be extended for an
interim  period  until  an  adequate  level  of  competition   is
established.  On  September 5, 1996, and January  20,  1997,  the
Regulator  published a consultation paper on price restraints  on
the supply businesses of RECs from April 1, 1998.

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

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

      The  price  control regulations which govern the authorized
area  supply  market  permit  the pass-through  to  customers  of
certain  permitted costs, which include the cost of  arrangements
such  as contracts for differences ("CFDs") to hedge against Pool
price   volatility.   Generally,  CFDs  are   contracts   between
generators and suppliers that have the effect of fixing the price
of  electricity for a contracted quantity of electricity  over  a
specific time period. Differences between the actual price set by
the  Pool  and the agreed prices give rise to difference payments
between  the parties to the particular CFD. At the present  time,
Northern's  forecast franchise supply market  demand  for  fiscal
year  1997  is  substantially hedged  through  various  types  of
agreements including CFDs.

     The most common contracts for supply to Non-Franchise Supply
Customers  are for a twelve-month term and contain  fixed  rates.
Northern  is exposed to two principal risks associated with  such
contracts: "load shape" risk (the risk associated with a shift in
the customer's usage pattern, including absolute amounts demanded
and  timing of amounts demanded) and "purchase" price  risk  (the
cost of purchased electricity relative to the price received from
the supply customer). Northern employs risk management methods to
maximize its return consistent with an acceptable level of  risk.
Generally  load shape risk decreases as Northern's  portfolio  of
supply  customers  in the non-franchise supply market  increases.
Northern  hedges purchase price risk by employing  a  variety  of
risk   management  tools,  including  management  of  its  supply
contract  portfolio and hedging contracts. Northern's ability  to
manage  its  purchase price risk depends, in part, on the  future
availability  of properly priced risk management mechanisms  such
as  CFDs. Northern is investigating whether owning its own source
of  generation or contracting for such source or sources would be
an appropriate method for partially managing purchase price risk.

Regulation Under the Electricity Act 1989

      The  Regulator.   The principal legislation  governing  the
structure  and  regulation  of the electricity  industry  in  the
United  Kingdom  is  the  Electricity Act.  The  Electricity  Act
established  the  industry structure described  above  so  as  to
enable  privatization  to take place. The  Electricity  Act  also
created  the institutional framework under which the industry  is
currently  regulated, including the office of the Regulator,  who
is  appointed by the United Kingdom Secretary of State for  Trade
and   Industry  (the  "UK  Secretary  of  State").  The   present
Regulator,  Professor Stephen Littlechild, was  appointed  for  a
five-year  term commencing September 1, 1989 and has  since  been
reappointed for a further five-year term.

      The Regulator's functions under the Electricity Act include
granting licenses to generate, transmit or supply electricity  (a
function that he exercises under a general authority from the  UK
Secretary  of  State); proposing modifications to  licenses,  and
making  license  modification references to  the  MMC;  enforcing
compliance with license conditions; advising the UK Secretary  of
State  in  respect  of the setting of each NFFO (defined  below);
calculating  the  Fossil  Fuel  Levy  (defined  below)  rate  and
collecting   the  levy;  determining  certain  disputes   between
electricity  licensees and customers; and  setting  standards  of
performance for electricity licensees.

      The  Regulator  exercises concurrently  with  the  Director
General  of  Fair Trading certain functions relating to  monopoly
and merger situations under the Fair Trading Act 1973 and certain
functions  relating  to courses of conduct  which  have,  or  are
intended or likely to have, the effect of restricting, distorting
or  preventing  competition  in the generation,  transmission  or
supply of electricity under the Competition Act 1980.

      The  Electricity  Act  requires the Regulator  and  the  UK
Secretary of State to exercise their functions in the manner each
considers  is  best  calculated to  secure  that  all  reasonable
demands  for  electricity are satisfied; to secure  that  license
holders  are  able to finance their licensed activities;  and  to
promote  competition in the generation and supply of electricity.
Subject  to  these  duties, the UK Secretary  of  State  and  the
Regulator are required to exercise their functions in the  manner
which each considers is best calculated: to protect the interests
of  customers  for electricity supplied by licensed suppliers  in
respect  of  price,  continuity of supply,  and  the  quality  of
electricity supply services; to promote efficiency and economy on
the  part of licensed electricity suppliers and the efficient use
of  electricity  supplied to customers; to promote  research  and
development  by  persons  authorized  by  license  to   generate,
transmit  or  supply electricity; and to secure the establishment
of  machinery for promoting the health and safety of  workers  in
the  electricity  industry. The UK Secretary  of  State  and  the
Regulator also have a duty to take into account the effect on the
physical environment of activities connected with the generation,
transmission or supply of electricity.

      In  performing  their duties to protect  the  interests  of
customers in respect of prices and other terms of supply, the  UK
Secretary  of  State and the Regulator have a duty to  take  into
account in particular the interests of customers in rural  areas.
In  performing their duties to protect the interests of customers
in  respect  of the quality of electricity supply services,  they
have  a duty to take into account in particular the interests  of
those who are disabled or of pensionable age.

      Licenses.   Generation  Licenses.   Unless  covered  by  an
exemption,  all electricity generators operating a power  station
in  the United Kingdom are required to have a generation license.
The  conditions attached to a generation license in  England  and
Wales  require the holder, among other things, to comply  with  a
grid code, be a member of the Pool and submit relevant generating
sets  for central dispatch. The conditions attached to generation
licenses  in Scotland require the holder, among other things,  to
comply  with  a  grid code. Failure to comply  with  any  of  the
generation  license  conditions may subject  the  licensee  to  a
variety  of  sanctions,  including  enforcement  orders  by   the
Regulator,  or  if  an enforcement order is  not  complied  with,
license revocation.

      PES  Licenses.  Each of the RECs, Scottish Power and Hydro-
Electric  has  a  PES  license for its  authorized  area  and  is
required,  under the Electricity Act, to supply electricity  upon
request  to  any  premises  in that  area,  except  in  specified
circumstances.  Each  PES is also required  not  to  discriminate
between  its  own  supply  business  and  other  users   of   its
distribution system. PESs are subject to separate price  controls
on  the amounts they may charge for the supply of electricity  to
Franchise   Supply  Customers  and  in  respect  of  distribution
charges.  The PES licenses also require the licensee  to  procure
electricity at the best price reasonably obtainable.

      On  September  5, 1996, and January 20, 1997 the  Regulator
issued  consultation papers to consider the application of supply
price  restraints  to  PESs effective from  April  1,  1998.  The
Regulator  has stated that he aims to publish final proposals  in
the summer of 1997.

      In England and Wales, each PES license limits the extent of
the  generation capacity in which the relevant REC  may  hold  an
interest  without  the  prior consent  of  the  Regulator  ("own-
generation  limits"). These own-generation limits,  expressed  in
megawatts,  currently  restrict the participation  of  a  REC  in
generation  to  a  level  of  approximately  15%  of  the   total
electricity  consumption in that REC's authorized  area.  In  the
case of Northern, the own-generation limit is fixed at 500 MW.

      The  Regulator  has stated that it would be  reasonable  to
consider a REC's request to increase its own-generation limit  on
condition that it accepted explicit restrictions on the contracts
it signed with its supply business, and that at a minimum the REC
would   be  prohibited  from  passing  additional  own-generation
contracts into its franchise supply market. He considers that  an
increase  in  own-generation limits subject to such  restrictions
could allow a REC to contribute more fully to the development  of
competition  in  generation without the allegation  that  it  was
exploiting its captive market and local monopoly position.

      Second  Tier  Supply Licenses.  Other than  a  PES  in  its
authorized  area  and  subject  to certain  other  exceptions,  a
supplier  of  electricity to premises in the United Kingdom  must
possess a second tier supply license. Subject to the restrictions
described  in  "Electricity Supply" above, second tier  licensees
may  compete  for the supply of electricity with one another  and
with  the  PES  for  the  relevant  area.  Currently,  there  are
approximately 39 second tier supply license holders  for  England
and Wales and approximately 25 second tier supply license holders
for Scotland.

      Transmission Licenses.  In England and Wales,  NGG  is  the
only   transmission  license  holder.  The  transmission  license
imposes  on NGC the obligation to operate the merit order  system
for  the  central  dispatch  of generating  sets  and  gives  NGC
responsibility for the economic purchasing of ancillary  services
from  generators and suppliers. The transmission license requires
NGC to offer terms on a non-discriminatory basis for the carrying
out  of  works  for  connection to, and use of, the  transmission
system and for use of the interconnections.

      Modifications to Licenses.  Subject to a veto power by  the
UK   Secretary  of  State,  the  Regulator  may  modify   license
conditions  with  the agreement of the license  holder.  He  must
first   publish   the   proposed   modifications   and   consider
representations or objections made. Modifications to the original
PES  licenses held by Northern have been previously made to  give
effect to price control reviews carried out by the Regulator.  CE
Electric  and the Regulator have agreed in principle on  proposed
terms  of  an  amendment to Northern's PES license in  connection
with the acquisition of Northern. These modifications conform  to
the legal assurances provided to the UK Secretary of State, which
are   generally  in  standard  form  in  connection  with  recent
acquisitions of RECs.

      If  the  Regulator and a license holder fail  to  agree  on
modifications, the may refer the matter to the MMC.  If  the  MMC
finds  that the matter referred to it has, or may be expected  to
have,  specified  effects adverse to the  public  interest  which
could  be  remedied  or prevented by a license modification,  the
Regulator  is required to make modifications that appear  to  him
requisite for the purpose of remedying or preventing the  adverse
effects   identified  by  the  MMC.  Modifications   to   license
conditions  may also be made by the UK Secretary of  State  as  a
consequence  of monopoly, merger or other competition  references
under general United Kingdom competition law.

      Term  and  Revocation of Licenses.  Northern's PES  license
shall   continue  indefinitely  unless  revoked.  Under  ordinary
circumstances,  the license only may be revoked  upon  25  years'
prior   notice,  which  notice  may  not  be  given  until  2000.
Otherwise,  the UK Secretary of State may revoke  a  PES  license
upon  not  less than 30 days' written notice to the  licensee  in
certain  specified circumstances including any failure to  comply
with  a final order of the Regulator requiring the license holder
to comply with its license conditions or requirements.

                 Other International Businesses

       Northern  Utility  Services  Limited.   Northern   Utility
Services  Limited ("Northern Utility") is an engineering  company
whose  role  is  to adapt, maintain and restore the  distribution
network  of  Northern  and  to sell  related  services  to  third
parties. Northern Utility has been able to make significant  cost
reductions  for  Northern during the past year  by  working  with
suppliers  in  order  to improve core processes,  close  selected
depot  locations, increase staff productivity and reduce material
and  plant costs. Northern Utility has pioneered techniques using
innovative  diagnostic testing equipment which reduces  the  need
for intrusive maintenance. The equipment can identify some of the
causes  of  potential  systems  failures  before  breakdown   and
subsequent loss of supply occurs. Also, the continued development
in  the  use of trenchless technology has brought both  financial
and  environmental benefits to Northern and its customers.  While
Northern Utility's largest customer is Northern Distribution,  it
increasingly  has  sold its services to third  parties.  Northern
Utility is Northern's largest employer.

      Northern Electric Retail Limited.  Northern Electric Retail
Limited  ("Northern Retail") sells electrical and gas  appliances
and   provides  account  collection  and  customer  services  for
Northern's  other businesses. Northern Retail's operating  profit
increased  to  pounds sterling 3.9 million for  the  year  ending
March  31, 1996 compared to pounds sterling 3.5 million  for  the
prior  year. This increase was primarily the result of  increased
sales  capabilities  and costs savings attributable  to  Northern
Retail's investment in information technology.

      Northern  Metering  Services  Limited.   Northern  Metering
Services  Limited  ("Northern Metering)  provides  meter  supply,
installation, refurbishment and certification services as well as
meter  operator  and data collection services. Northern  Metering
has  developed an energy profiling system which helps  businesses
reduce  costs  through the more efficient use of all  fuels,  not
just electricity.

       Sovereign   Exploration  Limited.   Sovereign  Exploration
Limited   ("Sovereign  Exploration"),  a  gas   exploration   and
production company, holds interests in the southern basin of  the
United  Kingdom sector of the North Sea, including a 5% ownership
of  the  Victor Field, which had a subsea pipeline connection  of
the north west extension of the field completed in 1995, and a 2%
ownership  interest  in the Schooner Field,  which  is  currently
under development. Sovereign Exploration also has a 20% ownership
interest  in  the  Windermere Field,  which  obtained  regulatory
consent for development in April 1996. Sovereign Exploration  has
interests  in other potential gas developments located in  United
Kingdom waters.
                                
               Domestic Power Generation Projects
                                
Projects in Operation

      The Coso Project.   In 1979, the Company entered into a 30-
year  contract  (the  "Navy Contract")  with  the  United  States
Department  of the Navy (the "Navy") to develop geothermal  power
facilities located on approximately 5,000 acres of the Naval  Air
Weapons Station at China Lake, California (150 miles northeast of
Los  Angeles). In 1985, the Company entered into a 30-year  lease
(the   "BLM  Lease")  with  the  United  States  Bureau  of  Land
Management  ("BLM")  for  approximately  19,000  acres  of   land
adjacent  to  the  land covered by the Navy  Contract.  The  Navy
Contract  and the BLM Lease provide for certain royalty  payments
as  a percentage of gross revenue and certain other formulas. The
Company  formed three joint ventures (the "Coso Joint  Ventures")
with  one  primary joint venture partner to develop and construct
the three facilities which comprise the Navy I project (the "Navy
I  Project"), the BLM project (the "BLM Project") and the Navy II
project   (the  "Navy  II  Project")  (collectively   the   "Coso
Project").

      The  Coso  Partnerships are as follows:  (i)  Coso  Finance
Partners,   which  owns  the  Navy  I  Project   (the   "Navy   I
Partnership"), (ii) Coso Energy Developers, which  owns  the  BLM
Project  (the "BLM Partnership") and (iii) Coso Power Developers,
which  owns  the Navy II Project (the "Navy II Partnership"  and,
together with the Navy I Partnership and the BLM Partnership, the
"Coso  Partnerships"). The Company holds ownership  interests  of
approximately 46% in the Navy I Partnership; approximately 48% in
the  BLM  Partnership; and 50% in the Navy  II  Partnership.  The
Company  consolidates  its  respective  share  of  the  operating
results  of  the Coso Partnerships into its financial statements.
Each  of  the  Coso  Partnerships  is  managed  by  a  management
committee  which consists of two representatives of  the  Company
and two representatives of the Company's partners. The Company is
the  managing  partner  of  each of  the  Coso  Partnerships  and
operates  the Coso Project, for which it receives fees  from  the
Coso Partnerships.

      The  Coso  Project sells all electricity generated  by  the
respective  plants  pursuant to three  long-term  SO4  Agreements
between the Navy I Partnership, the BLM Partnership, and the Navy
II  Partnership, respectively, and Edison. These  SO4  Agreements
provide for capacity payments, capacity bonus payments and energy
payments. Edison makes fixed annual capacity payments to the Coso
Partnerships  and,  to  the extent that capacity  factors  exceed
certain  benchmarks, is required to make capacity bonus payments.
The  price for capacity and capacity bonus payments is fixed  for
the  life  of  the SO4 Agreements. Energy is sold  at  increasing
fixed  rates  for  the first ten years after firm  operation  and
thereafter  at Edison's Avoided Cost of Energy. The  fixed  price
periods of the SO4 Agreements extend until at least August  1997,
March 1999 and January 2000 for each of the units operated by the
Navy  I, BLM and Navy II Partnerships, respectively, at rates  of
12.6  cents per kWh in 1996. The Company's share of the  revenues
received  by  the Coso Partnerships for 1994, 1995 and  1996  was
$137.0 million, $152.1 million and $160.5 million, respectively.

       The   physical  facilities  used  for  geothermal   energy
production are substantially the same at the Navy I, BLM and Navy
II Projects.

      Navy  I.    The geothermal resource for the Navy I  Project
currently  is produced from approximately 32 wells.  The  Navy  I
Project   consists  of  three  turbine  generators,   each   with
approximately  32  gross  MW of electrical  generating  capacity.
Based  on  an assumed net capacity of 80 MW, the Navy  I  Project
operated  at  an average operating capacity factor of  114.0%  in
1994, 112.1% in 1995, and 112.0% in 1996.

      BLM.    The BLM Project's geothermal resource currently  is
produced from approximately 20 wells. The BLM Project consists of
three  turbine  generators. Two of these turbine  generators  are
located at the BLM East site in a dual flash system, and  one  is
located at the BLM West site in a single flash system, each  with
an  electrical generating capacity of 32 gross MW.  Based  on  an
assumed  net  capacity of 80 MW, the BLM Project operated  at  an
average  operating capacity factor of  99.5% in 1994,  107.5%  in
1995 and 107.9% in 1996.

      Navy  II.   The geothermal resource for the Navy II Project
currently  is produced from approximately 25 wells. The  Navy  II
Project  consists  of three individual turbine  generators,  each
with approximately 32 gross MW of electrical generating capacity.
Based  on  an assumed net capacity of 80 MW, the Navy II  Project
operated  at an average operating capacity factor of   105.9%  in
1994, 111.3% in 1995 and 110.6% in 1996.

      Imperial  Valley Project.   The Company currently  operates
eight geothermal plants in the Imperial Valley in California (the
"Imperial Valley Project"). Four of these Imperial Valley Project
plants (the "Partnership Project") were developed by Magma  which
originally  owned a 50% interest. On April 17, 1996, the  Company
completed the Partnership Project Acquisition pursuant  to  which
the  Company acquired the remaining 50% interests in each of  the
Partnership  Project  plants  for $70  million.  The  Partnership
Project  consist  of  the Vulcan, Hoch (Del  Ranch),  Elmore  and
Leathers  projects (the "Vulcan Project," the "Hoch  (Del  Ranch)
Project,"  the  "Elmore  Project"  and  the  "Leathers  Project,"
respectively).

      The remaining four operating Imperial Valley Project plants
(the  "Salton Sea Projects") are wholly owned by subsidiaries  of
Magma.  Three  of these plants were purchased on March  31,  1993
from  Union  Oil  Company of California. These  geothermal  power
plants  consist of the Salton Sea I project (the  "Salton  Sea  I
Project"),  the  Salton  Sea  II  project  (the  "Salton  Sea  II
Project")  and  the Salton Sea III project (the "Salton  Sea  III
Project").  The  fourth plant, the Salton  Sea  IV  project  (the
"Salton  Sea  IV  Project"), commenced commercial  operations  in
1996.

      Based  on an assumed net capacity of 79.8 MW for  1994  and
1995  and  119.4  MW for 1996 (after the Salton  Sea  IV  Project
commenced commercial operation), the Salton Sea Projects operated
at a combined capacity factor of 90.8% in 1994, 86.5% in 1995 and
90.4%  in 1996. Based on an assumed net capacity of 148  MW,  the
Partnership  Project operated at a combined  capacity  factor  of
103.8% in 1994, 105.9% in 1995 and 104.8% in 1996.

      Vulcan.    The Vulcan Project sells electricity  to  Edison
under  a  30-year  SO4 Agreement that commenced on  February  10,
1986.  The  Vulcan Project has a contract capacity  and  contract
nameplate  of  29.5  MW and 34 MW, respectively.  Under  the  SO4
Agreement,  Edison  is  obligated to pay  the  Vulcan  Project  a
capacity payment, a capacity bonus payment and an energy payment.

      The  price for contract capacity payments is fixed for  the
life  of  such SO4 Agreement. The as-available capacity price  is
based on a payment schedule as approved by the CPUC from time  to
time.  The  contract energy payment increased each year  for  the
first  ten  years,  which period expired  on  February  9,  1996.
Thereafter,  the  energy payments are based on  Edison's  Avoided
Cost  of  Energy. The energy payment per kWh was  3.6  cents  for
1996.

      Hoch  (Del  Ranch).    The Hoch (Del Ranch)  Project  sells
electricity  to  Edison  under  a  30-year  SO4  Agreement   that
commenced on January 2, 1989. The contract capacity and  contract
nameplate  are  34 MW and 38 MW, respectively. The provisions  of
such  SO4  Agreement  are  substantially  the  same  as  the  SO4
Agreement with respect to the Vulcan Project.

      The  price for contract capacity payments is fixed for  the
life  of  the SO4 Agreement. The energy payments per kWh for  the
first  ten-year  period, which expires on January  1,  1999,  are
fixed at rates ranging from 12.6 cents for 1996 to 14.6 cents for
1998.  Thereafter, the energy payments will be based on  Edison's
Avoided Cost of Energy.

      Elmore.    The Elmore Project sells electricity  to  Edison
under  a 30-year SO4 Agreement that commenced on January 1, 1989.
The contract capacity and contract nameplate are 34 MW and 38 MW,
respectively.   The   provisions  of  such  SO4   Agreement   are
substantially the same as the SO4 Agreement with respect  to  the
Vulcan Project.

      The  price for contract capacity payments is fixed for  the
life  of  the SO4 Agreement. The energy payments per kWh for  the
first  ten-year period, which expires on December 31,  1998,  are
fixed  at rates ranging from 12.6 cents in 1996 to 14.6 cents  in
1998.  Thereafter, the energy payments will be based on  Edison's
Avoided Cost of Energy.

     Leathers.   The Leathers Project sells electricity to Edison
pursuant to a 30-year SO4 Agreement that commenced on January  1,
1990. The contract capacity and contract nameplate are 34 MW  and
38  MW,  respectively. The provisions of such SO4  Agreement  are
substantially the same as the SO4 Agreement with respect  to  the
Vulcan Project.

      The  price for contract capacity payments is fixed for  the
life  of  the SO4 Agreement. The energy payments per kWh for  the
first  ten-year period, which expires on December 31,  1999,  are
fixed  at rates ranging from 12.6 cents in 1996 to 15.6 cents  in
1999.  Thereafter,  the  energy payments are  based  on  Edison's
Avoided Cost of Energy.

      Salton  Sea  I  Project.   The Salton Sea I  Project  sells
electricity  to  Edison  pursuant to a 30-year  negotiated  power
purchase  agreement, as amended (the "Salton Sea I  PPA"),  which
provides  for capacity and energy payments. The contract capacity
and contract nameplate are each 10 MW.

      The  capacity  payment is based on the firm capacity  price
which is currently $132.58/kW-year. The contract capacity payment
adjusts  quarterly based on a basket of energy  indices  for  the
term  of  the Salton Sea I PPA. The energy payment is  calculated
using  a  Base Price (defined as the initial value of the  energy
payment  (4.701 cents per kWh for the second quarter  of  1992)),
which  is  subject to quarterly adjustments based on a basket  of
indices.  The  time  period weighted average energy  payment  for
Salton Sea I was 5.1 cents per kWh during 1996. As the Salton Sea
I  PPA is not an SO4 Agreement, the energy payments do not revert
to Edison's Avoided Cost of Energy.

      Salton  Sea  II Project.   The Salton Sea II Project  sells
electricity  to  Edison  pursuant  to  a  30-year  modified   SO4
Agreement that commenced on April 5, 1990. The contract  capacity
and contract nameplate are 15 MW (16.5 MW during on-peak periods)
and  20  MW, respectively. The contract requires Edison  to  make
capacity  payments, capacity bonus payments and energy  payments.
The  price  for  contract  capacity and contract  capacity  bonus
payments is fixed for the life of the modified SO4 Agreement. The
energy  payments  for  the first ten-year  period,  which  period
expires on April 4, 2000, are levelized at a time period weighted
average  of  10.6 cents per kWh. Thereafter, the  monthly  energy
payments will be Edison's Avoided Cost of Energy. For the  period
April  1,  1994  through March 31, 2004, Edison  is  entitled  to
receive, at no cost, 5% of all energy delivered in excess of  80%
of contract capacity.

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

      Salton Sea IV Project.   The Salton Sea IV Project consists
of  the consolidated expansion project pursuant to the Salton Sea
I  PPA  and the Fish Lake SO4 described below. The Salton  Sea  I
Project  had an option to supply an additional 20 MW of power  to
Edison  under  the Salton Sea I PPA. Magma, through  its  wholly-
owned  subsidiary, Fish Lake Power Company ("FLPC"), acquired  in
1992  a  modified SO4 Agreement (the "Fish Lake SO4")  to  supply
electric  power  to  Edison from a 16 MW geothermal  power  plant
proposed  to  be  built at Fish Lake in Esmeralda County,  Nevada
(the "Fish Lake Project").

      In  1994, Magma and Edison negotiated the consolidation  of
the  expansion portion of the Salton Sea I PPA and the Fish  Lake
SO4 (the "Amended PPA"). The Amended PPA was approved by the CPUC
on  April  26,  1995. The Amended PPA is a 30 year  contract  and
provides  for contract capacity payments based on a blended  rate
of  20/34  of $121.72/kW-year in 1992 dollars escalated quarterly
by  an index plus 14/34 of $158/kW-year. The Amended PPA provides
for energy payments pursuant to a schedule to commence in 1996 at
16/36  of  8.8 cents per kWh plus 20/36 of 4.7 cents per  kWh  in
1992 dollars escalated by an index.

      Construction of the Salton Sea IV Project was completed and
commencement of commercial operation occurred in 1996.

      Roosevelt Hot Springs.   The Company operates and  owns  an
approximately  70%  interest in a 25 MW  geothermal  steam  field
which  supplies geothermal steam to a power plant owned  by  Utah
Power  &  Light  Company ("UP&L") located on  the  Roosevelt  Hot
Springs  property  under  a  30-year steam  sales  contract.  The
Company obtained approximately $20.3 million of cash under a pre-
sale  agreement  with UP&L whereby UP&L paid in advance  for  the
steam  produced by the steam field. The Company must make certain
penalty  payments  to UP&L if the steam produced  does  not  meet
certain quantity and quality requirements.

     Desert Peak.   The Company is the owner and operator of a 10
MW  geothermal  plant  at Desert Peak, Nevada.  The  Desert  Peak
Project  had  been  selling electricity to Sierra  Pacific  Power
Company  ("SPPCo")  under  a power sales  contract  that  expired
December  31, 1995. A new letter agreement was executed providing
for the sale of capacity and energy at SPPCo's avoided cost.

      Royalty  Interest in the Mammoth Plants.    Magma  receives
royalty  revenues  from  a 10 MW and a 12 MW  contract  nameplate
geothermal power plant (the "First Mammoth Plant" and the "Second
Mammoth   Plant,"   respectively,   and   referred   to   herein,
collectively,   as  the  "Mammoth  Plants")  at  Mammoth   Lakes,
California. Electricity from the Mammoth Plants is sold to Edison
under  two long-term power purchase agreements. The First Mammoth
Plant and the Second Mammoth Plant began commercial operation  in
1985  and  1991,  respectively. Magma leases  both  property  and
geothermal resources to support the Mammoth Plants in return  for
certain  base royalty and bonus royalty payments. For  the  First
Mammoth  Plant and the Second Mammoth Plant, the base royalty  is
12.5% and 12%, respectively, of gross electricity sales revenues.
The bonus royalty for the Mammoth Plants is 50% of the excess  of
annual  gross  electricity sales revenues over an annual  revenue
standard based on the Mammoth Plants operating at 85% of contract
capacity.

      Royalty  Interest  in  the East Mesa  Plant.    Magma  also
receives  royalty  revenues  from  a  37  MW  contract  nameplate
geothermal power plant (with two units) at East Mesa in  Imperial
Valley, California (the "East Mesa Plant"). Electricity from  the
plant  is  sold to Edison pursuant to two SO4 Agreements formerly
held  by Magma, and Magma is entitled to receive a senior payment
of 4% of gross electricity sales revenues and a junior payment of
10%  of  gross electricity sales revenues. To date,  such  junior
payment has not been received.

      Yuma.    During  1992, the Company acquired  a  development
stage  50  MW  natural gas-fired cogeneration  project  in  Yuma,
Arizona (the "Yuma Project"). The Yuma Project is designed to  be
a QF under PURPA and to provide 50 MW of electricity to San Diego
Gas  & Electric Company ("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 power is  wheeled  to
SDG&E  over  transmission lines constructed and owned by  Arizona
Public  Service Company ("APS"). An agreement for interconnection
and  a  firm  transmission service agreement have  been  executed
between  APS  and the Yuma Project entity and have been  accepted
for filing by the Federal Energy Regulatory Commission ("FERC").

     The Yuma Project commenced commercial operation in May 1994.
The  project  entity has executed steam sales contracts  with  an
adjacent industrial entity to act as its thermal host in order to
maintain its status as a QF, which is a requirement of its  SDG&E
contract.  Since  the industrial entity has the right  under  its
agreement to terminate the agreement upon one year's notice if  a
change  in its technology eliminates its need for steam,  and  in
any  case to terminate the agreement at any time upon three years
notice,  there  can  be no assurance that the Yuma  Project  will
maintain  its  status as a QF. However, if the industrial  entity
terminates the agreement, the Company anticipates that it will be
able  to  locate an alternative thermal host in order to maintain
its  status as a QF or build a greenhouse at the site  for  which
the  Company  believes it would obtain QF status. A  natural  gas
supply  and  transportation  agreement  has  been  executed  with
Southwest Gas Corporation, terminable under certain circumstances
by the Company and Southwest Gas Corporation. The Yuma Project is
unleveraged other than intercompany debt.

       Saranac.     Saranac   is  a  240  MW  natural   gas-fired
cogeneration  facility located in Plattsburgh,  New  York,  which
began commercial operation in June 1994. Saranac has entered into
a  15-year power purchase agreement (the "Saranac PPA") with  New
York State Electric & Gas Corporation ("NYSEG"). Saranac is a  QF
and  has  entered  into  15-year steam purchase  agreements  (the
"Saranac   Steam   Purchase  Agreements")  with   Georgia-Pacific
Corporation and Tenneco Packaging , Inc.

      Saranac  has  a  15-year natural gas supply  contract  (the
"Saranac Gas Supply Agreement") with Shell Canada Limited ("Shell
Canada")  to  supply  100% of Saranac's fuel requirements.  Shell
Canada is responsible for production and delivery of natural  gas
to  the U.S.-Canadian border; the gas is then transported by  the
North Country Gas Pipeline Corporation ("NCGP") the remaining  22
miles  to the plant. NCGP is a wholly-owned subsidiary of Saranac
Power Partners, L.P. (the "Saranac Partnership"), which also owns
Saranac. NCGP also transports gas for NYSEG and Georgia-Pacific.

      Each  of  the  Saranac  PPA,  the  Saranac  Steam  Purchase
Agreements  and  the Saranac Gas Supply Agreement contains  rates
that  are  fixed  for  the  respective contract  terms.  Revenues
escalate at a higher rate than fuel costs.

      The Saranac Partnership is comprised of subsidiaries of (i)
Falcon  Seaboard and (ii) Tomen Corporation ("Tomen") and General
Electric Capital Corporation ("GECC").

      On  February 14, 1995, NYSEG filed with the FERC a Petition
for  a  Declaratory Order seeking FERC (i) to  declare  that  the
rates  NYSEG pays under its PPA with Saranac, which was  approved
by  the New York State Public Service Commission ("NYPSC"),  were
in  excess  of  the  level  permitted under  PURPA  and  (ii)  to
authorize  the  NYPSC to reform the PPA. 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 NYSEG/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 the request. On June  14,
1995, NYSEG petitioned the United States Court of Appeals for the
District of Columbia Circuit for review of FERC's April 12,  1995
order. FERC moved to dismiss NYSEG's petition for review on  July
28,  1995. Oral argument before the Court on NYSEG's petition and
FERC's motion to dismiss was held on December 2, 1996. The  Court
has  not  yet  acted on FERC's motion to dismiss.  Based  on  the
advice  of  its  outside  legal  counsel,  the  Company  believes
Saranac's position is meritorious and that it will prevail before
the D.C. Circuit if the matter is ultimately heard on its merits.

      Power Resources.   Power Resources is a 200 MW natural gas-
fired  cogeneration project located near Big Spring, Texas, which
has  a  15-year  power purchase agreement (the  "Power  Resources
PPA")  with  Texas  Utilities Electric Company.  Power  Resources
began commercial operation in June 1988. Power Resources is a  QF
and  has  entered  into a 15-year steam purchase  agreement  (the
"Power  Resources Steam Purchase Agreement") with  Fina  Oil  and
Chemical  Company  ("Fina"), a subsidiary of  Petrofina  S.A.  of
Belgium.

      Power  Resources has two natural gas supply  agreements  in
place. Natural Gas Clearinghouse ("NGCH") has entered into a  10-
year  agreement (the "NGCH Gas Supply Agreement") which ends  May
1997.  In addition, Power Resources has entered into an agreement
(the  "FSGC  Gas  Supply  Agreement") with  Falcon  Seaboard  Gas
Company  ("FSGC")  for  the remainder of  Power  Resources'  fuel
requirements  through  December  2003.  FSGC  has  fulfilled  its
commitments  to  Power Resources, Inc. ("PRI") to  date  using  a
combination of spot purchases plus short-term contracts. In  June
1995  FSGC  and  Louis  Dreyfus  Natural  Gas  Corp.  ("Dreyfus")
executed  an eight-year natural gas supply agreement (the  "FSGC-
Dreyfus Gas Supply Agreement"), with which FSGC will fulfill  its
supply commitment to PRI from October 1995 to the end of the term
of  the Power Resources PPA. Accordingly, through the combination
of  the NGCH Gas Supply Agreement and the FSGC-Dreyfus Gas Supply
Agreement, all gas requirements have been contracted for  through
the end of the Power Resources PPA.

      Each  of the Power Resources PPA, the Power Resources Steam
Purchase  Agreement  and the FSGC Gas Supply  Agreement  contains
rates  that are fixed for the respective contract terms. Revenues
escalate at a higher rate than fuel costs.

      NorCon.   NorCon is an 80 MW natural gas-fired cogeneration
facility   located  in  North  East,  Pennsylvania  which   began
commercial operation in December 1992. NorCon has a 25-year power
purchase  agreement (the "NorCon PPA") with Niagara Mohawk  Power
Corporation ("NIMO"). NorCon is a QF and has entered into  a  20-
year   steam  purchase  agreement  (the  "NorCon  Thermal  Energy
Agreement") with Welch Foods Inc., a Cooperative ("Welch Foods").

      NorCon  has  a  15-year natural gas  supply  contract  (the
"NorCon Gas Purchase Agreement") with Louis Dreyfus Gas Marketing
Corp. to supply 100% of NorCon's fuel requirements. A twenty-year
natural  gas transportation agreement has been entered into  with
National Fuel Gas Supply Corporation ("National Fuel") to provide
transportation to NorCon. Transportation costs are deducted  from
payments made pursuant to the NorCon Gas Purchase Agreement.  The
NorCon  PPA  has  rates  that are subject to  a  specified  floor
amount.  The NorCon Thermal Energy Agreement contains rates  that
escalate at an inflation-based index, and the NorCon Gas Purchase
Agreement's rates are fixed per a schedule for the contract term.

      NorCon  Power  Partners, L.P. (the  "NorCon  Partnership"),
which  owns  NorCon, is comprised of subsidiaries of  Falcon  and
Tomen.

      The NorCon project has had a number of on-going contractual
disputes  with NIMO which are unresolved and in August 1996  NIMO
proposed  a  buyout  of  the NorCon PPA  as  part  of  a  generic
restructuring by NIMO of all of its QF contracts in an effort  to
restructure  NIMO's  purchased  power  obligations  to  meet  the
challenge of industry deregulation and avoid what NIMO alleges as
the risk of a possible NIMO insolvency. The Company believes that
any contractual restructuring or even a NIMO insolvency would not
have  a  material  adverse effect on its  consolidated  financial
results of operations.

Projects in Development

       Salton  Sea  Minerals  Extraction.    The  Company  signed
agreements  with  a large international mining  company  in  1996
which  provide,  among  other things, for  the  Company,  at  its
option, to deliver power for the mineral extraction process  (the
"Salton  Sea  Extraction  Project"). The  initial  phase  of  the
project  would require delivery of approximately 15 MW.  A  pilot
plant  has  successfully produced zinc at the Company's  Imperial
Valley  Project.  Due to a failure to reach  agreement  with  the
mining  company  on  a satisfactory partnership  and  development
agreement  for  construction of a larger  extraction  plant,  the
Company  has determined to pursue the mineral extraction  project
on its own or with other partners. If successfully developed, the
mineral   extraction  process  will  provide  an  environmentally
compatible  and low cost minerals recovery methodology.  As  with
all  of  the  Company's  development projects,  this  project  is
subject to a number of uncertainties and implementation cannot be
assured.

      Glass  Mountain.   Under a Bonneville Power  Administration
("BPA") geothermal pilot program, the Company has been developing
a  30  net MW geothermal project which was originally located  in
the  Newberry Known Geothermal Resource Area in Deschutes County,
Oregon  (the  "Newberry Project"). Pursuant to  two  power  sales
contracts executed in September 1994, an affiliate of the Company
agreed  to  sell  20  MW to BPA and 10 MW  to  Eugene  Water  and
Electric  Board ("EWEB") from the Project. In addition,  BPA  and
EWEB together have an option to purchase up to an additional  100
MW  of  production from the project under certain  circumstances.
These   power   sales  contracts  provide  that   under   certain
circumstances  the  contracts may be utilized at  an  alternative
location.  Pursuant  to  its resource  exploration  program,  the
Company  has determined that the geothermal resource at  Newberry
is  not  sufficient to support the contracts and accordingly  has
determined to utilize the contracts at its leasehold position  in
Glass   Mountain  in  northern  California,  where  it  has   two
successful  production wells. The BPA contract arrangements  have
been  amended to reflect the relocation of the project  to  Glass
Mountain. Under the amended BPA contract arrangements,  BPA  will
purchase  30 MW from the project. The movement of the project  to
this  alternative  location  and BPA's  purchase  obligation  are
subject  to  obtaining  a  final environmental  impact  statement
relating  to  the new site location. Discussions  with  EWEB  are
continuing. Completion of this project is subject to a number  of
significant uncertainties and cannot be assured.

      The  BRPU  Process.   Magma sought new long-term final  SO4
Agreements  in  the Salton Sea area through the  bidding  process
adopted by the CPUC under its 1992 Biennial Resource Plan  Update
("BRPU").  In its BRPU, the CPUC cited the need for an additional
9,600  MW  of  power  production through 1999 among  California's
three investor-owned utilities, Edison, SDG&E and Pacific Gas and
Electric  Company.  Of  this amount, 275 MW  was  set  aside  for
bidding  by independent power producers (such as Magma) utilizing
renewable resources. Pursuant to an order of the CPUC dated  June
22,  1994 (confirmed on December 21, 1994), Magma was awarded 163
MW  for  sale to Edison and SDG&E, with in-service dates in  1997
and  1998.  On  February 23, 1995 the Federal  Energy  Regulatory
Commission ("FERC") issued an order finding that the CPUC's  BRPU
program  violated PURPA and FERC's implementing  regulations  and
recommended negotiated settlements. In response, the CPUC  issued
an  Assigned Commissioners Ruling encouraging settlements between
the  final  winning bidders and the utilities. The utilities  are
expected  to continue to challenge the BRPU and, in the light  of
the  regulatory uncertainty, there can be no assurance that power
sales  contracts will be executed or that any such projects  will
be  completed. In light of these developments, the Company agreed
to  execute an agreement with Edison on March 16, 1995  providing
that  in certain circumstances it would withdraw its Edison  BRPU
bid  in  consideration  for  the  payment  of  certain  sums.  In
December,  1996,  the  Company entered into a  confidential  cash
buyout agreement with SDG&E. These agreements are subject to CPUC
approval.

Regulatory, Energy and Environmental Matters
                                
United States

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

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

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

      In  addition,  many states are implementing or  considering
regulatory  initiatives designed to increase competition  in  the
domestic  power  generation  industry  and  increase  access   to
electric  utilities'  transmission and distribution  systems  for
independent   power  producers  and  electricity  consumers.   On
September 1, 1996, the California legislature adopted an industry
restructuring bill that would provide for a phased-in competitive
power  generation  industry  with a power  pool  and  independent
system operator and also would permit direct access to generation
for all power purchasers outside the power exchange under certain
circumstances.  Under the bill, consistent with the  requirements
of  PURPA,  existing qualifying facilities power sales agreements
would  be honored. The Company cannot predict the final  form  or
timing  of the proposed industry restructuring or the results  of
its operations.

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

United Kingdom

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

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

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

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

      The Conservative Party has held power in the United Kingdom
since  1979  and  currently  has a  one-seat  majority  over  all
parties. The next general election in the United Kingdom must  be
held  no  later than May 1997, and may be called at approximately
three  weeks'  notice  at any time before  then.  Certain  senior
members of the Labour Party, which is the main opposition  party,
have  recently made statements regarding policies which a  Labour
government  might  introduce,  including  a  windfall  assessment
proposed  to be levied on privatized utilities and referring  the
whole electricity industry to the competition authorities.
                                
Employees

      At  December  31,  1996, the Company and  its  subsidiaries
(including Northern) employed approximately 4,400 people. None of
the Coso Partnerships, the Falcon Project nor the Imperial Valley
Project  partnerships hire or retain any employees. All employees
necessary  to the operation of the Coso Project are  provided  by
the   Company  under  certain  plant  and  field  operations  and
maintenance  agreements. All employees necessary to  operate  the
Falcon and Imperial Valley Projects are provided by affiliates of
the  Company under certain administrative services and  operation
and  maintenance agreements. International development activities
in  Indonesia  and the Philippines are principally  performed  by
employees  of  affiliates of the Company and operations  will  be
performed  by  employees  of  the  local  project  entities.  The
Company's  affiliates currently maintain offices  in  Manila  and
Jakarta.

     Of Northern's employees, at December 31, 1996, approximately
86%  are represented by labor unions. All Northern employees  who
are  not  party to a personal employment contract are subject  to
collective  bargaining  agreements  that  are  covered  by  eight
separate  business agreements. These arrangements may be  amended
by  joint  agreement between the trade unions and the  individual
business  through negotiation in the appropriate  Joint  Business
Council.  Northern believes that its relations with its employees
are good.

Item 2.   Properties

       Property.     The  Company's  most  significant   physical
properties,  other  than  those  owned  by  Northern   (described
herein),  are its 19 operating power facilities and related  real
property  interests. The Company also maintains an  inventory  of
approximately  200,000 acres of geothermal property  leases.  The
Company  owns  its  principal executive offices  and  leases  its
offices  in Jakarta and Manila. Certain of the producing  acreage
owned by Magma is leased to Mammoth-Pacific as owner and operator
of  the  Mammoth Plants, and Magma, as lessor, receives royalties
from  the  revenues earned by such power plants. The Company,  as
lessee,  pays  certain royalties and other fees to  the  property
owners  and  other  royalty  interest holders  from  the  revenue
generated by the Imperial Valley Project.

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

      Northern  owns  the  freehold of  its  principal  executive
offices  in  Newcastle  upon  Tyne, England.  Northern  has  both
network  and  non-network land and building. At  March  31,  1996
Northern  had  freehold and leasehold interests in  approximately
7,500  network  properties,  comprising  principally  sub-station
sites.  The  recorded historical cost account net book  value  of
total  network  land and buildings at March 31, 1996  was  pounds
sterling 21.7 million. Northern owns, directly or indirectly, the
freehold  or  leasehold interests of such land and buildings.  At
March  31, 1996 Northern had freehold and leasehold interests  in
approximately  110  non-network  properties  comprising   chiefly
offices, former retail outlets, depots, warehouses and workshops.
The recorded historical cost account net book value of total non-
network  land and buildings at March 31, 1996 was pounds sterling
26.6 million.

Item 3.   Legal Proceedings

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

Item 4.   Submission of Matters to a Vote of Security Holders.
                                
Not applicable.
                                
                             PART II

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

The  Common  Stock is listed on the New York Stock Exchange  (the
"NYSE"), the Pacific Stock Exchange and the London Stock Exchange
under  the  symbol "CE." The following table sets forth  for  the
fiscal  quarters  indicated the high and low last  reported  sale
prices  of  the  Common Stock as reported on the  NYSE  Composite
Tape.

                            HIGH    LOW
1996                                 
Fourth Quarter             $33.62  $28.12
Third Quarter               31.87   22.87
Second Quarter              28.37   24.00
First Quarter               26.87   18.37

1995                                     
Fourth Quarter            $20.87  $17.87
Third Quarter              21.50   16.12
Second Quarter             17.12   15.50
First Quarter              18.87   15.37

      On  March  17, 1997, the last reported sale  price  of  the
Common Stock on the NYSE Composite Tape was $35.00 per share.  As
of  March  17,  1997, there were approximately 1,113  holders  of
record  of the Common Stock. The Company's present policy  is  to
reinvest  earnings in the business and pay no  dividends  on  its
Common Stock.

      The  Company's  10-1/4%  senior  discount  notes  due  2004
restrict  the payment of cash dividends based upon a formula  and
limit  the  amount of dividends and other distributions generally
to  no  more  than  50%  of  the Company's  accumulated  adjusted
consolidated net income as defined, subsequent to April 1,  1994,
plus the proceeds of any stock issuance.

      The  Company's  9 1/2% Senior Notes due 2006  restrict  the
payment  of  cash dividends based upon a formula  and  limit  the
amount of dividends and other distributions generally to no  more
than  50% of the Company's accumulated adjusted consolidated  net
income as defined, subsequent to April 1, 1994, plus the proceeds
of any stock issuances.

      The  Company's  ability to pay dividends is dependent  upon
receipt  of  dividends or other distributions from the  Company's
subsidiaries and the partnerships and joint ventures in which the
Company has interests. The availability of distributions from the
Company's  joint  ventures  is subject  to  the  satisfaction  of
various  covenants  and  conditions contained  in  the  venture's
financing  documents (such as those contained in the  Salton  Sea
Funding,   Coso  Funding,  or  international  project   financing
documents) and the Company anticipates that future project  level
financings   will   contain  certain   conditions   and   similar
restrictions on the distribution of cash flow to the Company.

      On  February  26,  1997, CalEnergy Capital  Trust  II  (the
"Trust"),  a  subsidiary of the Company and a statutory  business
trust formed under the laws of the state of Delaware, completed a
private placement of $150 million in aggregate amount of  6  1/4%
Trust Convertible Preferred Securities ("Trust Securities"), with
a  liquidation preference of $50 each.  Additionally, the initial
purchasers, Lehman Brothers Inc. and Donaldson Lufkin &  Jenrette
Securities  Corporation,  exercised  an  option  to  purchase  an
additional $30 million in aggregate amount of of Trust Securities
to  cover over-allotments.  Each of the Trust Securities will  be
convertible  at the option of the holder at any time into  1.1655
shares  of the Company's Common Stock, equivalent to a conversion
price  of  $42.90 per share, subject to adjustment under  certain
circumstances.  The Company owns all of the common securities  of
the  Trust.  The initial purchasers resold 3,506,000 of the Trust
Securities  ("Rule 144A Securities") to certain  persons  in  the
United  States in reliance on Rule 144A under the Securities  Act
of   1933.   The  Rule  144A  Securities  were  sold  for   their
liquidation  preference  of  $50  each  or  $175,300,000  in  the
aggregate.   In  connection with the purchase of  the  Rule  144A
Securities, the Company paid the initial purchasers a  commission
equal to 2 1/2% of the purchase price of the Rule 144A Securities
or $4,382,500 in the aggregate.

Item 6.   Selected Financial Data

      There  is  hereby incorporated by reference the information
which appears under the caption "Selected Financial Data" in  the
Annual Report.

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

      There  is  hereby incorporated by reference the information
which  appears  under  the caption "Management's  Discussion  and
Analysis of Financial Condition and Results of Operations" in the
Annual Report.

Item 8.   Financial Statements and Supplementary Data

      There  is  hereby incorporated by reference the information
which  appears in the Consolidated Financial Statements and notes
thereto in the Annual Report.

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

     Not applicable.
                            PART III

Item 10.  Directors and Executive Officers of the Registrant

      There  is  hereby incorporated by reference the information
which  appears under the caption "Information Regarding  Nominees
for  Election  as Directors, Directors Continuing in  Office  and
Directors Retiring at the Annual Meeting" in the Proxy Statement.

      The current executive and other officers of the Company and
their positions are as follows:

NAME                        POSITION
David L. Sokol*            Chairman of the Board and Chief Executive Officer
Gregory E. Abel*           President and Chief Operating Officer, CalEnergy
                           Europe and Chief Accounting Officer, CalEnergy
Douglas L. Anderson        Assistant General Counsel and Assistant
                           Secretary, CalEnergy and General Counsel,
                           CalEnergy Americas
Edward F. Bazemore*        Vice President, Human Resources
J. Douglas Divine          Vice President, Strategic Planning
Vincent R. Fesmire         Vice President, Construction and Engineering
Adrian M. Foley, III       Vice President, Marketing
Patrick J. Goodman         Controller
Brian K. Hankel            Treasurer
Frederick L. Manuel        Vice President, Indonesia
Thomas R. Mason*           President and Chief Operating Officer, CalEnergy
                           Americas
Steven A. McArthur*        Senior Vice President, General Counsel and Secretary
Donald M. O'Shei, Jr.*     President and Chief Operating Officer, CalEnergy Asia
Dale R. Schuster           Vice President, Implementation
Robert S. Silberman*       Senior Vice President, Marketing, Implementation
                           and Strategic Planning
James D. Stallmeyer        Assistant General Counsel, CalEnergy and General
                           Counsel, CalEnergy Asia
John G. Sylvia*            Senior Vice President and Chief Financial Officer
Russ L. Tenney             Vice President/General Manager, Philippines
Jonathan M. Weisgall       Vice President, Legislative and Regulatory Affairs

     *Executive officer of the Company.

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

      DAVID L. SOKOL, 40, Chairman of the Board of Directors  and
Chief  Executive Officer. Mr. Sokol has been CEO since April  19,
1993  and served as President of the Company from April 19,  1993
until  January  21, 1995. He has been Chairman of  the  Board  of
Directors  since May 1994. Mr. Sokol has been a director  of  the
Company  since  March  1991. Formerly, Mr.  Sokol  was  Chairman,
President  and  Chief  Executive  Officer  of  the  Company  from
February 1991 until January 1992. Mr. Sokol was the President and
Chief  Operating Officer of, and a director of, JWP,  Inc.,  from
January  27,  1992 to October 1, 1992. From November  1990  until
February  1991,  Mr. Sokol was the President and Chief  Executive
Officer of Kiewit Energy Company, the largest stockholder of  the
Company and a wholly owned subsidiary of PKS.

      GREGORY E. ABEL, 34, President and Chief Operating Officer,
CalEnergy   Europe  and  Chief  Accounting  Officer,   CalEnergy.
Mr.  Abel  joined the Company in 1992. Mr. Abel  is  a  Chartered
Accountant  and  from  1984  to 1992 he  was  employed  by  Price
Waterhouse.  As  a Manager in the San Francisco office  of  Price
Waterhouse,  he  was  responsible  for  clients  in  the   energy
industry.

      DOUGLAS  L.  ANDERSON, 39, Assistant  General  Counsel  and
Assistant  Secretary,  CalEnergy and General  Counsel,  CalEnergy
Americas. Mr. Anderson joined the Company in February 1993.  From
1990  to  1993, Mr. Anderson was a business attorney with Fraser,
Stryker,  Vaughn, Meusey, Olson, Boyer & Bloch,  P.C.  in  Omaha.
From  1987 through 1989, Mr. Anderson was a principal in the firm
Anderson & Anderson. Prior to that, from 1985 to 1987, he was  an
attorney  with  Foster, Swift, Collins & Coey, P.C.  in  Lansing,
Michigan.

      EDWARD  F.  BAZEMORE, 60, Vice President, Human  Resources.
Mr.  Bazemore joined the Company in July 1991. From 1989 to 1991,
he  was Vice President, Human Resources, at Ogden Projects,  Inc.
in  New Jersey. Prior to that, Mr. Bazemore was Director of Human
Resources  for Ricoh Corporation, also in New Jersey. Previously,
he  was  Director  of Industrial Relations for Scripto,  Inc.  in
Atlanta, Georgia.

      J.  DOUGLAS DIVINE, 40, Vice President, Strategic Planning.
Mr.  Divine joined the Company in September 1996. Prior to  that,
he  was  Director of Planning and Regulatory Affairs with  Falcon
Seaboard Resources Inc. from 1990 to 1996. From 1987 to 1990,  he
was  Senior Manager of Management Consulting Services with  Price
Waterhouse;  from  1984  to  1986  Mr.  Divine  was  Director  of
Operations   Review   Divisions  and   Executive   Assistant   to
Commissioner of the Public Utility Commission of Texas; and  from
1983 to 1984, he was Coordinator of Revenue and Economic Analysis
for the Governor's Office, State of Texas.

      VINCENT  R.  FESMIRE, 56, Vice President, Construction  and
Engineering.  Mr.  Fesmire joined the Company  in  October  1993.
Since  joining  the Company, Mr. Fesmire's responsibilities  have
shifted   from   project   development  and   implementation   to
construction  in  parallel  with  the  status  of  the  Company's
projects. Prior to joining the Company, Mr. Fesmire was  employed
for  19  years with Stone & Webster, an engineering firm, serving
in  various  management level capacities  with  an  expertise  in
geothermal design engineering.

      ADRIAN  M.  FOLEY,  III,  50,  Vice  President,  Marketing.
Mr.   Foley  joined  the  Company  in  January  1994  as  Project
Development Manager and continued in that capacity until  January
1997 when he was promoted to Vice President, Marketing. Prior  to
joining  CalEnergy,  Mr.  Foley was  Regional  Manager,  Business
Development  with  Ogden Projects, Inc. from  1989  to  1993  and
Executive  Vice  President with Rescom Development  Company  from
1980 to 1989.

      PATRICK J. GOODMAN, 30, Controller. Mr. Goodman joined  the
Company  in  June  1995, and served as Manager  of  Consolidation
Accounting   until  September  1996  when  he  was  promoted   to
Controller.  Prior  to joining the Company, Mr.  Goodman  was  an
accountant at Coopers & Lybrand.

      BRIAN  K.  HANKEL,  34, Treasurer. Mr.  Hankel  joined  the
Company  in February 1992 as Treasury Analyst and served in  that
position  to December 1995. Mr. Hankel was appointed to Assistant
Treasurer in January 1996 and was appointed Treasurer in  January
1997. Prior to joining the Company, Mr. Hankel was an Analyst  at
FirsTier  Bank  of  Lincoln from 1987 to 1992 and  Senior  Credit
Analyst at FirsTier from 1987 to 1988.

      FREDERICK MANUEL, 38, Vice President, Indonesia. Mr. Manuel
joined  the  Company in 1991. Prior to that, he was  employed  by
Chevron  Corporation  with responsibilities  including  land  and
offshore drilling, reservoir and production engineering,  project
management and technical research.

      THOMAS R. MASON, 53, President and Chief Operating Officer,
CalEnergy  Americas. Mr. Mason joined the Company in March  1991.
From October 1989 to March 1991, Mr. Mason was Vice President and
General  Manager  of  Kiewit  Energy  Company.  Prior  to   that,
Mr. Mason was Director of Marketing for Energy Factors, Inc. (now
Sithe  Energies U.S.A., Inc.), a non-utility developer  of  power
facilities.  Prior  to  that Mr. Mason  was  a  worldwide  Market
Manager of power generation for Caterpillar's Solar Gas Turbines,
a gas turbine manufacturer.

      STEVEN  A.  McARTHUR,  39, Senior Vice  President,  General
Counsel  and  Secretary.  Mr.  McArthur  joined  the  Company  in
February  1991.  From  1988 to 1991 he was  an  attorney  in  the
Corporate  Finance Group at Shearman & Sterling in San Francisco.
From  1984  to  1988 he was an attorney in the Corporate  Finance
Group at Winthrop, Stimson, Putnam & Roberts in New York.

      DONALD  M.  O'SHEI, JR., 37, President and Chief  Operating
Officer, CalEnergy Asia. Mr. O'Shei joined the Company in  August
1992. Prior to 1997, he served as General Manager--Indonesia  and
Vice  President  of CE International Investments,  Ltd.  for  the
Company.   From  1991  to  1992,  he  was  employed   by   Proven
Alternatives Capital Corporation as a Financial Analyst. Prior to
1991,  Mr. O'Shei served in the U.S. Army in the Special  Forces,
Airborne and Pathfinder Units.

      DALE  R.  SCHUSTER,  45,  Vice  President,  Implementation.
Mr.  Schuster  joined the Company in July 1994. From  1991  until
joining  the  Company  he was Senior Vice President  and  General
Manager of AutoInfo, Inc., a software development and information
systems  company,  and prior to that, he was Vice  President  and
General Manager of ValCom, Inc.

      ROBERT  S. SILBERMAN, 39, Senior Vice President, Marketing,
Implementation and Strategic Planning. Mr. Silberman  joined  the
Company in 1995. Prior to that, Mr. Silberman served as Executive
Assistant  to  the  Chairman  and  Chief  Executive  Officer   of
International Paper Company, as Director of Project  Finance  and
Implementation for the Ogden Corporation and as a Project Manager
in  Business  Development for Allied-Signal,  Inc.  He  has  also
served  as  the  Assistant Secretary of the Army for  the  United
States Department of Defense.

       JAMES   D.  STALLMEYER,  39,  Assistant  General  Counsel,
CalEnergy  and  General Counsel, CalEnergy Asia.  Mr.  Stallmeyer
joined  the  Company  in 1993. Mr. Stallmeyer  practiced  in  the
public finance and banking areas at Chapman and Cutler in Chicago
from  1984  to 1987 and in the corporate finance department  from
1989  to  1993. Prior to that, Mr. Stallmeyer was an attorney  in
the  public finance department of the Chicago office of  Skadden,
Arps,  Slate,  Meagher & Flom in 1987 and 1988 and  was  a  legal
writing instructor at the University of Illinois College  of  Law
in 1988 and 1989.

      JOHN  G.  SYLVIA,  38,  Senior  Vice  President  and  Chief
Financial  Officer. Mr. Sylvia joined the Company in  1988.  From
1985 to 1988, Mr. Sylvia was a Vice President of an international
financial  institution with responsibility for  global  corporate
and capital markets banking. From 1986 to 1990, Mr. Sylvia served
as an Adjunct Professor of Applied Economics at the University of
San  Francisco.  From  1982  to 1985,  Mr.  Sylvia  held  various
corporate finance positions with investment and financial firms.

       RUSS   L.  TENNEY,  43,  Vice  President/General  Manager,
Philippines. Mr. Tenney joined the Company in January 1995. Prior
to  that,  he  was  employed  by  Magma  Power  Company  and  its
affiliates in various capacities from 1981 to 1995. He  was  Vice
President,  Asian Operations from February 1994 to January  1995;
Vice  President, Project Development and Project Management  from
1992  to  1994;  Vice President, Technology and Capital  Projects
from  1989  to 1992; President and General Manager  of  Red  Hill
Geothermal, Inc., a subsidiary of Magma Power Company  from  1986
to 1989.

      JONATHAN  WEISGALL,  47,  Vice President,  Legislative  and
Regulatory Affairs. Mr. Weisgall joined the Company in May  1995.
Prior  to  that, Mr. Weisgall was an attorney in private practice
with  extensive energy and regulatory experience and is currently
Adjunct  Professor  of  Energy Law at Georgetown  University  Law
Center.

Item 11.  Executive Compensation

      There  is  hereby incorporated by reference the information
which  appears under the caption "Executive Officer and  Director
Compensation" in the Proxy Statement.

Item  12.   Security Ownership of Certain Beneficial  Owners  and
Management

      There  is  hereby incorporated by reference the information
which   appears   under  the  caption  "Security   Ownership   of
Significant Stockholders and Management" in the Proxy Statement.

Item 13.  Certain Relationships and Related Transactions

     There is hereby incorporated by reference the information
which appears under the caption "Certain Transactions and
Relationships" in the Proxy Statement.
                             PART IV

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

          (a)  Financial Statements and Schedule

          1.   Financial Statements

                Filed herewith and incorporated by reference  are
the  consolidated balance sheets of the Company and  subsidiaries
as  of  December  31,  1996,  and  December  31,  1995,  and  the
consolidated   statements   of   operations,   cash   flows   and
stockholders' equity for the years ended December 31, 1996,  1995
and 1994, and the related report of independent auditors.

          2.   Financial Statement Schedule

                 Independent  Auditor's  Report  on  Schedule  I,
Financial Statements of the Company (Parent Company only)

                 The   consolidated  Magma  financial   statement
schedules   which  are  excluded  from  the  annual   report   to
shareholders by Rule 14a-3(b) are required by Regulation S-X  (17
CFR 210) as Magma is an affiliate whose securities are pledged as
collateral and are included at Item 14(d).

     (b)  Reports on Form 8-K

           The  Company filed a Current Report on Form 8-K  dated
October  28, 1996 reporting the cash tender offer to acquire  all
the ordinary and preference shares of Northern.

           The  Company filed a Current Report on Form 8-K  dated
November  7,  1996  reporting the purchase of  an  equivalent  of
26.75% of the shares of Northern.

           The  Company filed a Current Report on Form 8-K  dated
November  8, 1996 reporting the acquisition of additional  shares
bringing its ownership total to 29.5% of Northern's shares.

           The  Company field a Current Report on Form 8-K  dated
December 24, 1996 reporting the acquisition of a majority of  the
shares  of  Northern  and the extension  of  its  offer  for  the
remaining equity interests in Northern.

     (c)  Exhibits

           The  exhibits listed on the accompanying Exhibit Index
(except  in  the  case of Exhibit 13.0, in which  case  only  the
portion  of  the  Annual Report which constitutes  the  Company's
Consolidated Financial Statements and notes thereto) are filed as
part of this Annual Report.

           For  the purposes of complying with the amendments  to
the  rules  governing Form S-8 effective July 13, 1990 under  the
Securities  Act  of  1933,  the  undersigned  Registrant   hereby
undertakes as follows, which undertaking shall be incorporated by
reference  into  the  Company's currently effective  Registration
Statements on Form S-8:

           Insofar  as  indemnification for  liabilities  arising
under  the  Securities Act of 1933 may be permitted to directors,
officers   and   controlling  persons  of  the  registrant,   the
registrant has been advised that in the opinion of the Securities
and  Exchange  Commission such indemnification is against  public
policy  as  expressed  in the Securities  Act  of  1933  and  is,
therefore,  unenforceable.  In  the  event  that  a   claim   for
indemnification against such liabilities (other than the  payment
by  the  registrant of expenses incurred or paid by  a  director,
officer of controlling person of the registrant in the successful
defense  of any action, suit or proceeding) is asserted  by  such
director,  officer or controlling person in connection  with  the
securities being registered, the registrant will, unless  in  the
opinion of its counsel the matter has been settled by controlling
precedent,  submit  to  a court of appropriate  jurisdiction  the
question of whether such indemnification by it is against  public
policy as expressed in the Act and will be governed by the  final
adjudication of such issue.

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

           The consolidated financial statements of Magma Company
and   subsidiaries  (financial  statements  of  affiliates  whose
securities are pledged as collateral) are filed as part  of  this
report immediately following Schedule I.


                                
                           SIGNATURES

Pursuant  to  the  requirements of Section 13  or  15(d)  of  the
Securities  Exchange Act of 1934, the Registrant has duly  caused
this  report  to  be  signed  on its behalf  by  the  undersigned
thereunto  duly  authorized,  in the  City  of  Omaha,  State  of
Nebraska, on this 18th day of March, 1997.

                              CALENERGY COMPANY, INC.


                               /s/ David L. Sokol*
                              By   David L. Sokol
                                   President and Chief Executive Officer


                               /s/ Steven A. McArthur
                              By   Steven A. McArthur
                                   Attorney-in-Fact


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

    Signature                                            Date

/s/   David L. Sokol*                                   March 18, 1997
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and
Director


/s/   John G. Sylvia                                    March 18, 1997
John G. Sylvia,
Senior Vice President,
Chief Financial Officer, and
Treasurer


/s/   Edgar D. Aronson*                                 March 18, 1997
Edgar D. Aronson
Director


/s/    Judith E. Ayres*                                 March 18, 1997
Judith E. Ayres
Director


/s/    James Q. Crowe*                                  March 18, 1997
James Q. Crowe
Director


*By:/s/  Steven A.McArthur                              March 18, 1997
Steven A. McArthur
Attorney-in-Fact


/s/    Richard K. Davidson*                             March 18, 1997
Richard K. Davidson
Director


/s/      David H. Dewhurst*                             March 18, 1997
David H. Dewhurst
Director


/s/     Richard R. Jaros*                               March 18, 1997
Richard R. Jaros
Director


/s/      Ben Holt*                                      March 18, 1997
Ben Holt
Director


/s/     David R. Morris*                                March 18, 1997
David Morris
Director

/s/      John R. Shiner*                                March 18, 1997
John R. Shiner
Director


/s/      Bernard W. Reznicek*                           March 18, 1997
Bernard W. Reznicek
Director


/s/     Walter Scott, Jr.*                              March 18, 1997
Walter Scott, Jr.
Director


/s/      David E. Wit*                                  March 18, 1997
David E. Wit
Director


*By:/s/  Steven A. McArthur                             March 18, 1997
Steven A. McArthur
Attorney-in-Fact


CalEnergy Company, Inc.                                Schedule I
Parent Company Only
Condensed Balance Sheets
as of December 31, 1996 and December 31, 1995
(dollars and shares in thousands, except per share amounts)

ASSETS                                       1996       1995


Cash and cash equivalents               $    68,449 $   46,042
Restricted cash                              21,208     40,631
Short-term investment                           192     34,190
Investments  in  and advances to
 subsidiaries and joint  ventures         1,952,612  1,197,588
Equipment, net                                9,797      1,999
Notes receivable - joint ventures            27,375     27,474
Deferred charges and other assets            90,234     76,680


 Total assets                            $2,169,867 $1,424,604


LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable                         $      708 $      215
Other accrued liabilities                    12,291      4,241
Parent company debt                       1,146,685    842,205
Deferred income taxes                        12,688     25,348
 Total liabilities                        1,172,372    872,009

Deferred income                              12,775      9,063
Company-obligated mandatorily redeemable
 convertible preferred securities of subsidiary trust holding
 solely convertible debentures              103,930        ---

Stockholders' equity:
 Preferred stock - authorized 2,000 shares      ---        ---
 Common stock - par value $0.0675 per share,
   authorized 80,000 shares, issued 63,747
   and 50,680 shares,outstanding  63,448
   and 50,593 shares, respectively            4,303      3,421
 Additional paid in capital                 563,567    343,406
 Retained earnings                          297,520    205,059
  Cumulative  effect of foreign currency
   translation  adjustment                   29,658        ---
 Treasury stock-299 and 87 common shares
  at cost                                    (8,787)    (1,348)
  Unearned  compensation - restricted stock  (5,471)    (7,006)
 Total stockholders' equity                 880,790    543,532
 Total liabilities and stockholders'
  equity                                 $2,169,867 $1,424,604


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


CalEnergy Company, Inc.                             Schedule I
Parent Company Only                                (continued)
Condensed Statements Of Operations
for the three years ended December 31, 1996
(dollars in thousands)
                                         1996   1995        1994

Revenue:

Equity in undistributed earnings
 of subsidiary companies and
 joint ventures                     $  91,528  $52,960   $55,757

Cash dividends and distributions
 from subsidiary companies and
 joint ventures                       102,428   88,360    19,691
Interest and other income              22,459   16,065    20,598

 Total revenues                       216,415  157,385    96,046

Expenses:

General and administration             22,958   16,354     7,926

Interest, net of capitalized interest  54,484   46,985    32,284
Dividends on convertible preferred
 securities of subsidiary trust         4,691      ---       ---
 Total expenses                        82,133   63,339    40,210

Income before provision for income
 taxes                                134,282   94,046    55,836

Provision for income taxes             41,821   30,631    17,002

Income before extraordinary item       92,461   63,415    38,834
Extraordinary item, less applicable
 income taxes of $945                     ---      ---    (2,007)

Net income                             92,461   63,415    36,827

Preferred dividends                       ---    1,080     5,010

Net  income available to common
 stockholders                         $92,461  $62,335   $31,817
Income  per share before
 extraordinary item                   $  1.60  $  1.25   $   .95
Extraordinary item                        ---      ---   $  (.06)
Net income per share-primary          $  1.60  $  1.25   $   .89
Net income per share-fully diluted    $  1.50  $  1.18   $   .88
Average number of shares 
 outstanding-primary                   57,870   49,971    35,721
Fully diluted shares                   67,164   57,742    40,166

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


CalEnergy Company, Inc.                                Schedule I
Parent Company Only                                    (continued)
Condensed Statements Of Cash Flows
for the three years ended December 31, 1996
(dollars in thousands)
                                                1996        1995      1994
  

Cash flows from operating activities         $(51,621)   $(33,469)   $15,146

Cash flows from investing activities:
Increase in advances to and investments in subsidiaries
  and joint ventures                         (531,410)   (747,516)   (24,959)
Decrease  (increase) in short-term
 investments                                   33,998      15,810    (50,000)
Decrease (increase) in restricted cash         19,423      50,274    (77,370)
Other                                          (5,179)     10,699    (29,292)

Cash flows from investing activities         (483,168)   (670,733)  (181,621)

Cash flows from financing activities:
Proceeds from sale of common and treasury
 stocks and exercise of stock options          54,935     299,649      1,580
Proceeds from issuance of parent
 company debt                                 419,150     200,000    400,000
Proceeds from convertible preferred
 securities of subsidiary trust               103,930         ---        ---
Purchase of treasury stock                    (12,008)     (1,590)   (65,119)
Defeasance of 12% senior notes                    ---         ---    (35,730)
Deferred charges relating to debt financing    (8,811)        ---     (8,895)

Cash flows from financing activities          557,196     498,059    291,836

Net increase (decrease) in cash and
 cash equivalents                              22,407    (206,143)   125,361

Cash  and cash equivalents at beginning
 of period                                     46,042     252,185    126,824

Cash  and cash equivalents at end of
 period                                      $ 68,449   $  46,042   $252,185

Supplemental disclosures:
Interest  paid (net of amount capitalized)   $  1,705   $   5,172   $  1,477

Income taxes paid                            $ 23,211   $  14,812   $  4,926


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

INDEPENDENT AUDITORS' REPORT


To the Board of Directors and Shareholders
CalEnergy Company, Inc.
Omaha, Nebraska

We have audited the consolidated financial statement of CalEnergy Company, Inc.
and subsidiaries as of December 31, 1996 and 1995, and for each of the three
years in the period ended December 31, 1996, and have issued our report thereon
dated January 31, 1997 (February 27, 1997 as to Notes 6 and 20 to the
consolidated financial statements); such financial statements and reports are
included in your 1996 Annual Report to Stockholders and are incorporated herein
by reference.  Our audits also included the financial statement schedule of
CalEnergy Company, Inc. and subsidiaries, listed in Item 14.  This financial
statement schedule is the responsibility of the Company's management.  Our
responsibility is to express an opinion based on our audits.  In our opinion,
such financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.


Deloitte & Touche, LLP
Omaha, Nebraska
January 31, 1997 (February 27, 1997 as to Notes 6 and 20 to the consolidated
financial statements)


              MAGMA POWER COMPANY AND SUBSIDIARIES
     (A wholly-owned subsidiary of CalEnergy Company, Inc.)
                                
                  INDEX TO FINANCIAL STATEMENTS


The  following consolidated financial statements of  Magma  Power
Company  and  the  related independent accountants'  reports  are
included in Items 14(d):

Independent Auditors' Report--Deloitte & Touche LLP         F-2

Report of Independent Accountants--Coopers & Lybrand L.L.P. F-3

Consolidated balance sheets at December 31, 1996 and 1995   F-4

Consolidated statements of operations for the three years
ended December 31, 1996                                     F-5

Consolidated statements of stockholder's equity for the three
years ended December 31, 1996                               F-6

Consolidated statements of cash flows for the three years
ended December 31, 1996                                     F-7

Notes to consolidated financial statements                  F-8

All  schedules have been omitted because they are not  applicable
or  not required, or because the required information is shown in
the consolidated financial statements or notes thereto.


                  INDEPENDENT AUDITORS' REPORT


Board of Directors and Shareholder
Magma Power Company
Omaha, Nebraska


We  have audited the accompanying consolidated balance sheets  of
Magma  Power Company and subsidiaries, a wholly-owned  subsidiary
of  CalEnergy Company, Inc., as of December 31, 1996 and 1995 the
related   consolidated   successor  statements   of   operations,
stockholder's  equity and cash flows for the  years  then  ended.
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 successor financial statements
present  fairly, in all material respects, the financial position
of  Magma Power Company and subsidiaries at December 31, 1996 and
1995 and the results of their operations and their cash flows for
the  years  then  ended  in  conformity with  generally  accepted
accounting principles.



Deloitte & Touche, LLP
Omaha, Nebraska
January 31, 1997

               REPORT OF INDEPENDENT ACCOUNTANTS


To the Shareholders and Board
of Directors of Magma Power Company

We   have   audited  the  accompanying  consolidated  predecessor
statements of operation, changes in stockholders' equity and cash
flows for the year ended December 31, 1994 of Magma Power Company
and    subsidiaries.    The   financial   statements   are    the
responsibility  of the Company's management.  Our  responsibility
is   to  express  an  opinion  on  these  consolidated  financial
statements based on our audit.

We  conducted  our  audit 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  our
audit provides a reasonable basis for our opinion.

In our opinion, the consolidated predecessor financial statements
referred  to above present fairly, in all material respects,  the
consolidated  financial  position  of  Magma  Power  Company  and
Subsidiaries at December 31, 1994 and the consolidated results of
their  operations and their cash flows for the year in the period
ended  December  31,  1994 in conformity with generally  accepted
accounting principles.

As  discussed in Note 3, subsequent to December 31, 1994, all  of
the  outstanding common stock of Magma Power Company was acquired
by CalEnergy Company, Inc.


                                  COOPERS & LYBRAND L.L.P.

San Diego, California
March 10, 1995
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
CONSOLIDATED BALANCE SHEETS
as of December 31, 1996 and 1995
dollars and shares in thousands except per share amounts

ASSETS                                       1996       1995

Cash and cash equivalents                $   13,429 $  25,564
Joint venture cash and investments                -    13,863
Restricted cash                              23,695    69,540
Accounts receivable                          44,966    25,496
Due from parent                              84,434    29,669
Properties,  plants, contracts
 and equipment,  net                      1,225,684 1,016,133
Excess of cost over fair value of net assets
 acquired, net                              299,055   306,379
Deferred charges and other assets            62,874    53,597

 Total assets                            $1,754,137$1,540,241


LIABILITIES AND STOCKHOLDER'S EQUITY
Liabilities:
Accounts payable                         $      852 $   4,572
Other accrued liabilities                    51,429    58,740
Construction and project loans              137,881    91,570
Salton Sea notes and bonds                  538,982   452,088
Limited recourse senior secured notes       200,000   200,000
Deferred income taxes                       226,709   197,029

 Total liabilities                        1,155,853 1,003,999

Commitments and contingencies (Note 12)

Stockholder's equity:
Preferred stock - par value $0.10 per share,
 authorized 1,000 shares                       ---        ---
Common stock - par value $0.10 per share,
 authorized 30,000 shares, outstanding
 100 shares                                    ---        ---
Additional paid in capital                  501,626   501,626
Retained earnings                            96,658    34,616


 Total stockholder's equity                 598,284   536,242


Total liabilities and stockholder's equity$1,754,137$1,540,241

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


MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
CONSOLIDATED STATEMENTS OF OPERATIONS
for the three years ended December 31, 1996
dollars in thousands

                                      1996      1995     1994


Successor                  Predecessor
Revenue:
Sales of electricity and steam    $ 249,293  $162,418    $158,374
Royalty income                        6,846    19,962      21,067
Interest and other income             9,368    17,812      11,441

 Total revenues                     265,507   200,192     190,882

Cost and expenses:
Plant operations                     57,122    47,384      52,122
General and administration           10,731    13,680      13,942
Depreciation and amortization        69,853    46,895      23,985
Interest                             67,652    60,596      13,177
Less  interest capitalized          (27,382)  (24,568)       (708)
Other non-plant costs                   ---       ---      29,983

 Total expenses                     177,976   143,987     132,501

Income  before provision for
 income taxes and minority
 interest                            87,531    56,205      58,381
Provision for income taxes           25,489    17,498      19,832

Income before minority interest      62,042    38,707      38,549
Minority Interest                       ---     4,091         ---

Net income                          $62,042   $34,616     $38,549

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


MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
for the three years ended December 31, 1996
dollars and shares in thousands

<TABLE>
<CAPTION>
                                                                       Unrealized
                                   Outstanding           Additional    Gains From
                                     Common     Common    Paid-In      Marketable   Retained
                                     Shares     Stock     Capital      Securities   Earnings    Total
<S>                                  <C>       <C>        <C>             <C>       <C>        <C>
Predecessor:
Balance January 1, 1994              23,990    $2,399     $144,996        $583      $203,940   $351,918
Adjustment to tax effect of Dow
 option purchase                        ---       ---       (3,045)        ---           ---     (3,045)
Net change in unrealized gains
 from marketable securities             ---       ---          ---        (583)          ---       (583)
Other equity transactions, net          127        12        2,965         ---           ---      2,977
Net income                              ---       ---          ---         ---        38,549     38,549

Balance, December 31, 1994           24,117     2,411      144,916         ---       242,489    389,816

Net income in 1995 prior
 to acquisition                         ---       ---          ---         ---         4,091      4,091

Successor:
Purchase accounting push-down
 adjustments, net                   (24,049)   (2,415)     332,857         ---      (246,580)    83,862
Contributions from parent               ---       ---       22,947         ---           ---     22,947
Other equity transactions, net           32         4          906         ---           ---        910
Net income                              ---       ---          ---         ---        34,616     34,616

Balance, December 31, 1995              100       ---      501,626         ---        34,616    536,242

Net income                              ---       ---          ---         ---        62,042     62,042

Balance, December 31, 1996              100    $  ---     $501,626      $  ---      $ 96,658   $598,284

</TABLE>

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


MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the three years ended December 31, 1996
Dollars in thousands
<TABLE>
<CAPTION>

                                                     1996        1995     1994
                                                       Successor        Predecessor
<S>                                               <C>          <C>        <C>
Cash flows from operating activities:
Net income                                        $ 62,042     $ 34,616   $ 38,549
Adjustments to reconcile net cash flow from operating activities:
 Minority interest                                     ---        4,091        ---
 Provision for deferred income taxes                 7,277        7,614      8,168
 Depreciation and amortization                      69,853       46,895     23,985
 Write-off of junior SO4 receivable                    ---          ---     14,502
Changes in other items:
 Accounts receivable                                (7,735)       4,354   (12,081)
  Accounts  payable and other accrued liabilities    3,325       17,599    13,677
Other                                                  ---       (3,446)  (13,832)

Net cash flows from operating activities           134,762      111,723    72,968

Cash flows from investing activities:
Capital expenditures                              (190,152)   (171,063)   (58,045)
Purchase of Mission interest                       (58,044)        ---        ---
Purchase of Magma, net of cash acquired                ---    (907,614)       ---
Decrease (increase) in restricted cash              59,071      (4,785)     7,473
Increase in other assets                            (3,345)    (24,037)      (527)

Net  cash flows from investing activities         (192,470) (1,107,499)   (51,099)

Cash flows from financing activities:
Due from parent                                    (53,203)    (29,669)       ---
Proceeds from debt offerings                       135,000     675,000        ---
Repayment of Salton Sea notes & bonds              (48,106)    (22,912)       ---
Repayment of project loans                        (102,999)   (124,839)  (166,020)
Proceeds from construction and other loans         101,018      36,863    130,000
Proceeds from sale of common stock and
exercise of stock options                              ---         910      2,977
Advances from parent                                   ---     499,850        ---
 Other, net                                            ---         ---     (3,042)

  Net cash flows from financing activities          31,710   1,035,203    (36,085)

Net  increase (decrease) in cash and
 cash equivalents                                  (25,998)    39,427     (14,216)
Cash  and  cash equivalents at beginning 
 of period                                          39,427        ---      18,017

Cash  and  cash equivalents at end of period      $ 13,429   $ 39,427     $ 3,801

Interest paid (net of amounts capitalized)        $ 49,129   $ 50,840     $13,235

Income taxes paid                                 $    ---   $ 14,812     $11,350

</TABLE>

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


MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
for the three years ended December 31, 1996
dollars and shares in thousands

1. BUSINESS

Magma  Power  Company (the "Company" or "Magma"), a  wholly-owned
subsidiary  of CalEnergy Company, Inc. (CalEnergy), is  primarily
engaged  in  the  exploration for and development  of  geothermal
resources and conversion of such resources into electrical  power
and steam for sale to electric utilities, and the development  of
other environmentally responsible forms of power generation.

The  Company currently operates eight geothermal power plants  in
the  Imperial Valley in California. On April 17, 1996 the Company
completed  the acquisition of Edison Mission Energy's partnership
interests  (the  "Partnership  Interest  Acquisition")  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.  The remaining  four
plants  are  the  Salton Sea Project which  are  wholly-owned  by
subsidiaries  of  the  Company.  These  geothermal  power  plants
consist  of the Salton Sea I, Salton Sea II, Salton Sea III,  and
Salton  Sea IV.  The Salton Sea IV project completed construction
in the current year and commenced operations in June 1996.

In 1995 the Company, through its wholly-owned subsidiary, Visayas
Geothermal  Power  Company ("VGPC"), began  construction  of  the
Malitbog  Geothermal  Project on  the  island  of  Leyte  in  the
Republic of the Philippines.  Unit I was deemed complete on  July
25, 1996.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements include the accounts of the
Company   and  its  wholly-owned  subsidiaries.  Prior   to   the
Partnership  Interest  Acquisition,  the  consolidated  financial
statements include the Company's proportionate share of the joint
ventures in which it had an undivided interest in the assets  and
was  proportionately  liable for its share of  liabilities.   All
significant inter-enterprise transactions and accounts have  been
eliminated.  The results of operations of the Company include the
Company's  proportionate share of the results  of  operations  of
entities acquired as of the date of acquisition.

The  December 31, 1996 and 1995 consolidated financial statements
reflect the acquisition by CalEnergy, the resulting push down  to
the  Company of the accounting as a purchase business combination
and  minority  interest for the non-owned periods  consisting  of
100%  for the period of January 1-9, 1995 and 49% for the  period
January 10, 1995-February 23, 1995.

Restricted Cash

The  restricted cash balance includes primarily commercial paper,
money  market securities and mortgage backed securities,  and  is
mainly  composed of restricted accounts for debt service  reserve
funds  and a capital expenditure fund.  The debt service  reserve
funds  are  legally  restricted to  their  use  and  require  the
maintenance of specific minimum balances.

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  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  production
wells  are ten to twenty years depending on the type of the well;
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.

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  $7,664 and $6,906 at December  31,  1996  and
1995, respectively, and are included in other assets.

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 Magma Acquisition by the Company has been accounted for as  a
purchase  business combination pursuant to the principle  of  APB
Opinion No. 16 "Business Combinations."  In applying APB No.  16,
all  identifiable  assets acquired and liabilities  assumed  were
assigned a portion of the cost of acquiring Magma, equal to their
fair  values  at  the  date of the acquisition  and  include  the
following:

Power  sales  agreements are amortized separately  over  (1)  the
remaining  portion (1 to 5 years) of the scheduled price  periods
of  the  power sales agreements and (2) the 20 year avoided  cost
periods  of  the  power sales agreements using the  straight-line
method.

Mineral reserves are amortized on the units of production method.

Excess of Cost over Fair Value

Total acquisition costs in excess of the fair values assigned  to
the net assets acquired are amortized over a 40 year period using
the straight-line method.

Capitalization of Interest and Deferred Financing Costs

Prior  to the commencement of operations, interest is capitalized
on the costs of the plants and geothermal 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 implicit interest method.

Revenue Recognition

Revenues are recorded based upon service rendered and electricity
and  steam  delivered to the end of the month.  See  Note  4  for
contractual  terms  of power sales agreements.  Royalties  earned
from  providing geothermal resources to power plants operated  by
other  geothermal  power  producers are recorded  on  an  accrual
basis.   Prior to the Partnership Interest Acquisition, royalties
contractually  payable to the Company by the Partnership  Project
were recorded on an accrual basis, net of the Company's 50% share
of   the   corresponding   partnership  project   expense.    All
intercompany  royalties were eliminated after the acquisition  of
the remaining 50% partnership interest.

Income Taxes

The Company is included in the consolidated income tax returns of
CalEnergy  and  affiliates.  The provision for  income  taxes  is
computed  on  a  separate  return basis. The  Company  recognizes
deferred  tax  assets  and liabilities based  on  the  difference
between  the financial statement and the tax basis of the  assets
and liabilities using enacted tax rates in effect for the year in
which the differences are expected to reverse.

Fair Values of Financial Instruments

The following methods and assumptions were used by the Company in
estimating  fair  values  of financial instruments  as  discussed
herein.   Fair values have been estimated based on quoted  market
prices  for  debt  issues listed on exchanges.   Fair  values  of
financial instruments that are not actively traded are  based  on
market  prices of similar instruments and/or valuation techniques
using market assumptions.

Cash Equivelents

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.

Impairment of Long-Lived Assets

On  January  1, 1996, the Company adopted Statement of  Financial
Accounting  Standards No. 121 ("SFAS 121"), "Accounting  for  the
Impairment of Long-Lived Assets and for Long-Lived Assets  to  be
Disposed  Of" which requires that long-lived assets  and  certain
identifiable  intangibles  be reviewed  for  impairment  whenever
events  or  changes in circumstances indicate that  the  carrying
amount of an asset may not be recoverable.  The adoption of  SFAS
121  did  not  have a material effect on the Company's  financial
statements.

Reclassification

Certain  amounts in the fiscal 1995 and 1994 financial statements
and  supporting  footnote disclosures have been  reclassified  to
conform  to  the fiscal 1996 presentation.  Such reclassification
did  not  impact  previously  reported  net  income  or  retained
earnings.

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.

3.   ACQUISITIONS

Magma Power Company

On  January 10, 1995, CalEnergy acquired approximately 51% of the
outstanding shares of common stock of the Company through a  cash
tender  offer and completed the acquisition on February 24,  1995
by  acquiring the remaining 49% of outstanding shares  of  common
stock through a merger (the "Magma Acquisition").

The  Magma  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 Magma, equal to their fair values at the date
of  the  acquisition.   The total cost  of  the  acquisition  was
allocated as follows:

   Cash                                          $  62,116
   Operating facilities and project cash           291,365
   Power sales agreements                          173,730
   Mineral reserves                                160,768
   Construction in progress                         93,174
   Process license and other                        39,304
   Excess of cost over fair value of net assets
    acquired, net of deferred taxes of $168,914    137,455
                                                  $957,912

The Magma Tender Offer was financed with a $245,600 facility from
Credit  Suisse (the "Tender Facility").  Loans under  the  Tender
Facility  were made to CalEnergy on a nonrecourse basis,  secured
by the Company stock acquired, and CalEnergy lent the proceeds of
such  loans  to the Company in exchange for a secured  term  note
from the Company (the "Tender Note").

Secured bank financing in the amount of $500,000 was provided  by
Credit  Suisse (the "Merger Facilities") on specified  terms  and
subject  to customary conditions.  Such funds, together with  the
net proceeds of a public equity offering of CalEnergy and general
corporate  funds  of  CalEnergy were used to complete  the  Magma
acquisition.

In  July  1995,  CalEnergy recapitalized Magma  and  the  related
Merger Facilities from proceeds received through the issuance  of
notes and bonds as described in Note 6.

Edison Mission Energy's Partnership Interest

On April 17, 1996 the Company completed the acquisition of Edison
Mission Energy's partnership interests (the "Partnership Interest
Acquisition")   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.

The Partnership Interest 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 the Partnership Interest, equal to their fair values at
the date of the acquisition.

The total cost of the acquisition was allocated as follows:

Cash                              $  12,956
Restricted cash                      13,226
Power sales agreements               78,036
Other assets                         20,254
Project loans                       (48,161)
Liabilities                          (5,311)
                                  $  71,000

Unaudited  pro  forma  combined revenue and  net  income  of  the
Company and the Partnership Interest for the twelve months  ended
December 31, 1996 and 1995, as if the acquisition had occurred at
the beginning of 1995 after giving

effect   to  certain  pro  forma  adjustments  related   to   the
acquisition  were $284,193 and $63,135 compared to  $291,812  and
$52,477, respectively.

4. PROPERTIES, PLANTS, CONTRACTS AND EQUIPMENT

Properties,   plants,  contracts  and  equipment   comprise   the
following at December 31:
                                        1996        1995

Power plants                         $557,006     $306,197
Wells and resource development        114,492       84,442
Power sales agreements                264,371      185,749
Licenses and equipment                 46,290       46,290
    Total operating facilities        982,159      622,678

Less accumulated depreciation and
  amortization                       (103,702)    (41,577)

   Net operating facilities           878,457      581,101
Mineral reserves                      189,198      173,547

Construction in progress:
 Malitbog                             155,410      146,735
 Salton Sea Expansion                     ---      108,769
 Other development                      2,619        5,981


 Total                             $1,225,684   $1,016,133

Imperial Valley Project Operating Facilities

The   Partnership  Project  and  the  Salton  Sea   Project   are
collectively  referred to as the Imperial  Valley  Project.   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
 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

Significant Customers and Contracts

All  of  the  Company's sales of electricity  from  the  Imperial
Valley   Project,  which  comprise  approximately  88%  of   1996
electricity and steam revenues, are to Southern California Edison
("SCE") and are under long-term power purchase contracts.

The  Partnership Project sells all electricity generated  by  the
respective  plants  pursuant  to four  long-term  SO4  Agreements
between  the  project and SCE.  These SO4 Agreements provide  for
capacity  payments, capacity bonus payments and energy  payments.
SCE makes fixed annual capacity payments to the projects, and  to
the  extent  that capacity factors exceed certain  benchmarks  is
required to make capacity bonus payments.  The price for capacity
and  capacity  bonus payments is fixed for the life  of  the  SO4
Agreements.   Energy is sold at increasing fixed  rates  for  the
first  ten years of each contract and thereafter at SCE's Avoided
Cost of Energy.

The scheduled energy price periods of the Partnership Project SO4
Agreements   extended  until  February  1996   for   the   Vulcan
Partnership  and extend until December 1998, December  1998,  and
December  1999  for  each of the Del Ranch, Elmore  and  Leathers
Partnerships, respectively.  Excluding Vulcan, which is receiving
Edison's  Avoided  Cost of Energy, the Company's  SO4  Agreements
provide for energy rates ranging from 12.6 cents per kWh in  1996
to  15.6 cents per kWh in 1999.  The weighted average energy rate
for all of the Company's SO4 Agreements was 9.7 cents per kWh  in
1996.

The  Salton Sea I project sells electricity to SCE 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 5.1 cents per kWh during 1996.  As the  Salton
Sea  I  PPA is not an SO4 Agreement, the energy payments  do  not
revert to SCE's Avoided Cost of Energy.  The capacity payment  is
approximately $1,100 per annum.

The Salton Sea II and Salton Sea III projects sell electricity to
SCE  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  period
expires in April 2000 and February 1999 are levelized at  a  time
period  weighted average of 10.64 per kWh and 9.84  per  kWh  for
Salton Sea II and Salton Sea III, respectively.  Thereafter,  the
monthly  energy  payments will be SCE's Avoided Cost  of  Energy.
For  Salton Sea II only, SCE is entitled to receive, at no  cost,
5%  of all energy delivered in excess of 80% of contract capacity
for  the period April 1, 1994 through March 31, 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.

For  the year ended December 31, 1996, SCE's average Avoided Cost
of  Energy was 2.5 cents per kWh which is substantially below the
contract  energy  prices earned for the year ended  December  31,
1996.   Estimates  of SCE'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  could  decline
significantly  after  the expiration of the respective  scheduled
payment periods.

Magma sought new long-term final SO4 power purchase agreements in
the  Salton Sea area through the bidding process adopted  by  the
CPUC  under its 1992 Biennial Resource Plan Update ("BRPU").   In
its  BRPU, the CPUC cited the need for an additional 9,600 MW  of
power  production through 1999 among California's three investor-
owned  utilities,  Edison,  SDG&E and Pacific  Gas  and  Electric
Company.   Of  this amount, 275 MW was set aside for  bidding  by
independent  power producers (such as Magma) utilizing  renewable
resources.  Pursuant to an order of the CPUC dated June 22,  1994
(confirmed  on December 21, 1994), Magma was awarded 163  net  MW
for  sale to Edison and SDG&E, with in-service dates in 1997  and
1998.   On  February  23,  1995  the  Federal  Energy  Regulatory
Commission ("FERC") issued an order finding that the CPUC's  BRPU
program  violated PURPA and FERC's implementing  regulations  and
recommended negotiated settlements.  In response, the CPUC issued
an  Assigned Commissioners Ruling encouraging settlements between
the  final winning bidders and the utilities.  The utilities  are
expected  to continue to challenge the BRPU and, in the light  of
the  regulatory uncertainty, there can be no assurance that power
sales  contracts will be executed or that any such projects  will
be completed.  In light of these developments, the Company agreed
to  execute an agreement with Edison on March 16, 1995  providing
that  in certain circumstances it would withdraw its Edison  BRPU
bid  in  consideration  for  the payment  of  certain  sums.   In
December,  1996,  the  Company entered into a  confidential  cash
buyout  agreement with SDG&E.  These agreements  are  subject  to
CPUC approval.

Unit  I of the Malitbog Project was deemed complete in July  1996
and  began  receiving capacity payments pursuant to the  Malitbog
Energy  Conversion Agreement ("ECA") in July 1996.  The  Malitbog
Project  is being built, owned and operated by VGPC, a Philippine
general  partnership  that is wholly-owned,  indirectly,  by  the
Company.  The Malitbog Project is structured as a ten year Build-
Own-Operate-Transfer ("BOOT") project, in which the Company  will
be  responsible  for implementing construction of the  geothermal
power   plant  and,  as  owner,  for  providing  operations   and
maintenance  for  the  ten  year BOOT  period.   The  electricity
generated   by  the  Malitbog  Project  is  sold  to  PNOC-Energy
Development  Corporation ("PNOC-EDC"), which is also  responsible
for  supplying the facility with the geothermal steam.   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.

PNOC-EDC  is  obligated  to  pay for electric  capacity  that  is
nominated each year by VGPC, irrespective of whether PNOC-EDC  is
willing  or  able to accept delivery of such capacity.   PNOC-EDC
pays  VGPC 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).  The Capacity Fee serves to recover the capital  costs
of  the  project, to recover fixed operating costs and  to  cover
return  on  investment.  The Energy Fee is designed to cover  all
variable  operating  and maintenance costs of  the  power  plant.
Payments  under the Malitbog 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, which will
be used to pay Philippine peso-denominated expenses.  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  Malitbog  ECA
are  supported  by  the Government of the Philippines  through  a
performance undertaking.

Royalties

Royalty  expense for the years ended December 31, 1996 and  1995,
which  is included in general and administration expense  in  the
consolidated statement of operations comprise the following:

                        1996      1995
 Vulcan                 $ 361   $ 1,207
 Leathers               2,203     1,968
 Elmore                 1,883     1,713
 Del Ranch              2,255     1,932
 Salton Sea 1 & 2         634     1,147
 Salton Sea 3           1,334     2,431
 Salton Sea 4           1,558         -
      Total           $10,228   $10,398

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 1996
was  approximately  5.2%.  The royalties  are  paid  to  numerous
recipients based on varying percentages of electrical revenue  or
steam production multiplied by published indices.

5. CONSTRUCTION AND PROJECT LOANS

Construction and project loans comprise the following at December
31:

                               1996             1995
 Construction loans         $137,881          $36,863
 Project loans                     -           54,707
                            $137,881          $91,570

Draws  on the construction loan for the Malitbog geothermal power
project at December 31, 1996 totaled $137,881.   At December  31,
1996 and 1995 the weighted average interest rates were 8.15%  and
8.42%,  respectively.  Credit Suisse and OPIC have  provided  the
construction  and term loan facilities.  The eight  year  project
term  loan  facilities will be at variable interest  rates.   The
international  bank portion of the debt will be  insured  by  the
Overseas   Private   Investment  Corporation   ("OPIC")   against
political risks and the Company's equity contribution to VGPC  is
covered   by  political  risk  insurance  from  the  Multilateral
Investment Guarantee Agency and OPIC.

All project loans were repaid in 1996.

6.   DEBT OFFERINGS

Pursuant to separate financing agreements, substantially all  the
assets  of  the Company are pledged or encumbered to  support  or
otherwise provide security for existing debt.

On June 20, 1996 and July 25, 1995, CalEnergy through its wholly-
owned   subsidiary,  Salton  Sea  Funding  Corporation  ("Funding
Corporation"),  completed  sales to  institutional  investors  of
$135,000  and  $475,000, respectively, of Salton  Sea  Notes  and
Bonds  (the "Notes and Bonds").  The Salton Sea Notes  and  Bonds
are  nonrecourse  to the Company.   The Funding Corporation  debt
securities were offered as follows:

                Senior Secured Series     Due            Rate         Amount
July 25, 1995          A Notes       May 30, 2000        6.69%       $232,750
July 25, 1995          B Bonds       May 30, 2005        7.37%        133,000
July 25, 1995          C Bonds       May 30, 2010        7.84%        109,250
June 20, 1996          D Notes       May 30, 2000        7.02%         70,000
June 20, 1996          E Bonds       May 30, 2011        8.30%         65,000

The  Salton Sea Notes and Bonds are secured by the Company's four
existing Salton Sea plants 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.
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.  It should not be assumed that  any
asset  of  any such subsidiary will be available to  satisfy  the
obligations of the Company or any of its other such subsidiaries;
provided,  however, that unrestricted cash or other assets  which
are available for distribution may, subject to applicable law and
the terms of financing arrangements of such parties, be advanced,
loaned, paid as dividends or otherwise distributed or contributed
to  the Company or affiliates thereof.  Substantially all of  the
assets   of   each  subsidiary  listed  below  (except  Vulcan/BN
Geothermal Power Company and certain other subsidiaries  involved
in  project financing activities) have been encumbered to  secure
obligations owed to the creditors of such subsidiary:

Fish Lake Power Company
Salton Sea Brine Processing L.P.
Salton Sea Power Generation L.P.
Vulcan Power Company
CalEnergy Operating Company
Salton Sea Funding Corporation
Salton Sea Power Company
Salton Sea Royalty Company
Vulcan/BN Geothermal Power Company
Del Ranch, L.P.
Elmore, L.P.
Leathers, L.P.

Pursuant   to   the  Depository  Agreement,  Funding  Corporation
established a debt service reserve fund in the form of  a  letter
of  credit  in the initial amount of $70,430 from which scheduled
interest and principal payments can be made.

Annual repayments of the Salton Sea Notes and Bonds for the years
beginning January 1, 1997 are as follows:

          1997            $90,228
          1998            106,938
          1999             57,836
          2000             25,072
          2001             22,376
          Thereafter      236,532
                         $538,982

On  July  21, 1995, concurrent with the issuance of the  $475,000
Salton  Sea Notes and Bonds, CalEnergy issued $200,000 of 9  7/8%
Limited  Recourse  Senior Secured Notes Due 2003  (the  "Notes").
Interest  on the Notes is payable on June 30 and December  30  of
each year, commencing December 1995.  The 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,
CalEnergy's  interest in a secured Magma note and general  assets
of  CalEnergy equal to the Restricted Payment Recourse Amount (as
defined in the Note Indenture) which was $0 at December 31, 1996.

At  any  time or from time to time on or prior to June 30,  1998,
CalEnergy  may, at its option, use all or a portion  of  the  net
cash  proceeds of a CalEnergy equity offering (as defined in  the
Note  Indenture)  and shall at any time use all of the  net  cash
proceeds  of  any Magma equity offering (as defined in  the  Note
Indenture)  to redeem up to an aggregate of 35% of the  principle
amount of the Notes originally issued at a redemption price equal
to 109.875% of the principle amount thereof plus accrued interest
to the redemption date.  On or after June 30, 2000, the Notes are
redeemable at the option of the CalEnergy, 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.
7.   INCOME TAXES

Provision  for  income  tax  is comprised  of  the  following  at
December 31:
                            1996         1995       1994

                         Successor       Predecessor
Currently payable:
 State                    $ 6,420      $ 2,228    $ 2,554
 Federal                   11,792        7,656      9,190

                           18,212        9,884     11,744

Deferred:
 State                      1,232          924        537
 Federal                    4,908        6,690      7,551
 Foreign                    1,137          ---        ---
                            7,277        7,614      8,088
 Total                    $25,489      $17,498    $19,832

The   deferred   expense   is  primarily  temporary   differences
associated with depreciation and amortization of certain assets.

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

                             1996         1995       1994

Successor                            Predecessor

Federal statutory rate                  35.00 %        35.00 %       35.00 %
Percentage  depletion in excess 
 of cost depletion                      (5.15)         (6.44)        (3.57)
Investment and energy tax credits      (12.30)         (2.05)         (.17)
State taxes, net of federal tax effect   4.26           4.34          3.84
Goodwill amortization                    3.10           4.99           .23
Tax effect of foreign income             1.30            ---           ---
Lease investment                          ---          (3.88)        (8.12)
Other                                    2.91           (.83)         6.76

                                        29.12 %        31.13 %       33.97 %

Deferred  tax liabilities (assets) are comprised of the following
at December 31:
                                                     1996          1995


Depreciation and amortization, net                $265,193       $232,025
Other                                                  788            ---
                                                   265,981        232,025

Tax credits                                        (33,407)      (26,422)
Jr. SO4 royalty receivable                          (5,865)       (5,865)
Other                                                  ---        (2,709)
                                                   (39,272)      (34,996)
 Net deferred taxes                               $226,709      $197,029

During  1993, the Company realized a tax benefit of $13,581  from
the  purchase  of  Dow's option to acquire  Magma  Power  Company
common  stock.   This benefit resulted in a decrease  in  current
income  taxes  payable  of $8,880, an increase  in  deferred  tax
liabilities  of  $93 and an increase in deferred  tax  assets  of
$4,794.   During 1994, the estimated tax benefit was  reduced  by
$3,045.

8. 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   techniques.
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.

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  in  the
consolidated balance sheets under the indicated captions.


                                         1996                  1995
                                             Estimated              Estimated
                                  Carrying      Fair      Carrying    Fair
                                   Value        Value       Value     Value
  Financial liabilities:
  Construction and project loans 137,881      137,881      91,570     91,570
  Salton Sea notes and bonds     538,982      531,807     452,088    459,629
  Limited recourse senior
    secured notes                200,000      212,560     200,000    210,500

9.   Other Non-Plant Costs:

During 1994, the Company wrote-off its entire outstanding accrued
Junior  SO4 royalty receivable from GEO East Mesa.  The write-off
amounted  to $14,502 and is included in other non-plant costs  on
the  accompanying  statements of operations.  The  write-off  was
deemed  necessary due to the inability of the East Mesa Plant  to
convert  its  construction loans into a term  loan  as  had  been
expected to occur in 1994.  Conversion of the construction  loans
into  a  term  loan,  which  is  a prerequisite  to  the  Company
collecting  the  Junior  SO4  royalties,  has  been   placed   on
indefinite hold.

Upon the signing of the Merger Agreement between the Company  and
CalEnergy  on  December 9, 1994 terminated Magma  personnel  were
entitled  to receive severance benefits under existing change  of
control  agreements.  For the year ended December 31,  1994,  the
Company   accrued  $5,195  relating  to  the  change  of  control
agreements   in   other  non-plant  costs  in  the   accompanying
statements of operations.

Also  included  in  other  non-plant costs  in  the  accompanying
statements of operations were $9,861 in merger expenses  incurred
by  the  Company for legal, financial advisory and other services
used during 1994.


10.STOCKHOLDER EQUITY

In  1987,  1993,  and  1994 the Company entered  into  technical,
engineering,  and  management agreements with  The  Dow  Chemical
Company ("Dow").  Under the 1987 Agreement, the Company agreed to
pay  for those services either with shares of Magma Power Company
common stock valued at the then market price or cash.  Under  the
1993  and 1994 Agreements, the Company agreed to pay for services
provided by Dow in cash which totaled $450 in 1996, $500 in  1995
and  $205 in 1994.  The 1993 Dow agreement was terminated  during
1995.

The  1987  Agreement granted Dow an option for  2,000  shares  of
Magma Power Company common stock at option prices that started at
$17.00  per  share,  a negotiated price that  exceeded  the  then
current market price, and which escalated over a four-year period
commencing  one  year  after operation of the  Hoch  Plant  to  a
maximum  exercise price of $21.00 in 1993.  On October  12,  1993
the  Company purchased the option by issuing 857,143 newly issued
and  unregistered shares.  The number of shares issued was  based
on  the difference between the exercise price of $21.00 per share
and  the  market  price on October 12, 1993 discounted  $1.00  to
$37.50.   During  1993,  shareholders' equity  was  increased  by
$13,581  representing  the tax effect of  the  shares  purchased.
During 1994, the tax effect was adjusted downward by $3,045.

11.INCENTIVE STOCK OPTION PLANS

Upon  the  completion of the Merger with CalEnergy (see Note  3),
all  remaining outstanding stock options under Magma's 1987  Plan
and  1994  Plan, whether or not then exercisable, were  canceled.
Each holder of a canceled company option became then entitled  to
a  cash  payment equal to the difference between $38.75  and  the
canceled  option price.  A total payment of approximately  $8,500
for all of the canceled options was paid by CalEnergy as part  of
the Merger consideration.

12.  LITIGATION

As  of  December  31,  1996  there were no  material  outstanding
lawsuits.
                         EXHIBIT INDEX

3.1  The   Company's   Restated  Certificate   of   Incorporation
     (incorporated  by reference to Exhibit 3.1 of the  Company's
     Form 10-K for the year ended December 31, 1992, File No.  1-
     9874 (the "1992 Form 10-K")).

3.2  Certificate   of   Amendment  of  the   Company's   Restated
     Certificate   of   Incorporation,  dated   June   23,   1993
     (incorporated by reference to the Company's Form 8-A,  dated
     July 28, 1993, File No. 1-9874 ("Form 8-A")).

3.3  Certificate   of   Amendment  of  the   Company's   Restated
     Certificate  of  Incorporation  dated,  February  23,   1995
     (incorporated  by reference to Exhibit 3.3 to the  Company's
     Form  10-K/A  Amendment  (dated  March  31,  1995)  to   the
     Company's  Form 10-K for the year ended December  31,  1994,
     File No. 1-9874 (the "1994 Form 10-K")).

3.4  Certificate  of  Ownership and Merger, effective  March  26,
     1996.  (incorporated  by reference to  Exhibit  3.4  of  the
     Company's  Form 10-K for the year ended December  31,  1995,
     File No. 1-9874 (the 1995 Form 10-K")).

3.5  The Company's Certificate of Designation with respect to the
     Company's   Series  C  Redeemable  Convertible  Exchangeable
     Preferred Stock, dated November 20, 1991, including  a  form
     of  the  9.5% Convertible Subordinated Debentures  due  2003
     (incorporated  by reference to Exhibit 3.1 of the  Company's
     1992 Form 10-K).

3.6  The Company's By-Laws as amended through February 21, 1997.

4.1  Specimen   copy   of   form  of  Common  Stock   Certificate
     (incorporated  by reference to Exhibit 4.1 to the  Company's
     Form 10-K for the year ended December 31, 1993, File No.  1-
     9874 (the "1993 Form 10-K")).

4.2  Shareholders  Rights  Agreement  between  the  Company   and
     Manufacturers  Hanover  Trust Company  of  California  dated
     December 1, 1988 (incorporated by reference to Exhibit 1  to
     Company's Form 8-K dated December 5, 1988, File No. 1-9874).

4.3  Amendment  Number  1 to Shareholder Rights Agreement,  dated
     February 15, 1991 (incorporated by reference to Exhibit  4.2
     to the Company's 1992 Form 10-K).

4.4  Escrow  Deposit Agreement between Bank of American  National
     Trust and Savings Association and the Company dated March 3,
     1994  (incorporated  by  reference to  Exhibit  4.7  to  the
     Company's 1993 Form 10-K).

10.1 Joint Venture Agreement for China Lake Joint Venture between
     the Company and Caithness Geothermal 1980 Ltd., restated  as
     of  January  1, 1984 (incorporated by reference  to  Exhibit
     10.1 to the Company's Registration Statement on Form S-1, 33-
     7770).

10.2 Amended  Joint  Venture  Agreement  for  Coso  Land  Company
     between  the  Company  and Caithness Geothermal  1980  Ltd.,
     dated  as  of  June 1, 1983 (incorporated  by  reference  to
     Exhibit 10.3 to the Company's Registration Statement on Form
     S-1, 33-7770).

10.3 Amended  General  Partnership  Agreement  for  Coso  Finance
     Partners  between China Lake Operating Company  and  ESCA  I
     L.P.  dated  July  13, 1988 (incorporated  by  reference  to
     Exhibit 10.3 to the Company's 1992 Form 10-K).
10.4 First  Supplemental  Amendment to the Amended  and  Restated
     General  Partnership  Agreement for  Coso  Finance  Partners
     between China Lake Operating Company and ESCA L.P. (Undated)
     (incorporated by reference to Exhibit 10.4 to the  Company's
     1992 Form 10-K).

10.5 Second  Supplemental Amendment to the Amended  and  Restated
     General  Partnership  Agreement for  Coso  Finance  Partners
     between China Lake Operating Company and ESCA L.P. dated  as
     of  July 13, 1988 (incorporated by reference to Exhibit 10.5
     to the Company's 1992 Form 10-K).

10.6 Third  Supplemental  Amendment to the Amended  and  Restated
     General  Partnership  Agreement for  Coso  Finance  Partners
     between China Lake Operating Company and ESCA L.P. dated  as
     of  December 16, 1992 (incorporated by reference to  Exhibit
     10.6 to the Company's 1992 Form 10-K).

10.7 General  Partnership Agreement for Coso Finance Partners  II
     between China Lake Geothermal Management Company and ESCA II
     L.P.  dated  July  7,  1987 (incorporated  by  reference  to
     Exhibit 10.7 to the Company's 1992 Form 10-K).

10.8 Restated  General  Partnership  Agreement  for  Coso  Energy
     Developers between Coso Hotsprings Intermountain Power  Inc.
     and  Caithness Coso Holdings L.P. dated as of March 31, 1988
     (incorporated by reference to Exhibit 10.8 to the  Company's
     1992 Form 10-K).

10.9 First   Amendment   to  the  Restated  General   Partnership
     Agreement for Coso Energy Developers between Coso Hotsprings
     Intermountain Power, Inc. and Caithness Coso Holdings,  L.P.
     dated  as  of  March 31, 1988 (incorporated by reference  to
     Exhibit 10.9 to the Company's 1992 Form 10-K).

10.10      Second  Amendment to the Restated General  Partnership
     Agreement for Coso Energy Developers between Coso Hotsprings
     Intermountain  Power, Inc. and Caithness Coso Holdings  L.P.
     dated as of December 16, 1992 (incorporated by reference  to
     Exhibit 10.10 to the Company's 1992 Form 10-K).

10.11      Amended and Restated General Partnership Agreement for
     Coso  Power  Developers between Coso Technology  Corporation
     and  Caithness  Navy  II  Group L.P.  dated  July  31,  1989
     (incorporated by reference to Exhibit 10.11 to the Company's
     1992 Form 10-K).

10.12      First  Amendment  to the Amended and Restated  General
     Partnership   for   Coso  Power  Developers   between   Coso
     Technology  Corporation and Caithness  Navy  II  Group  L.P.
     dated  as  of  March 19, 1991 (incorporated by reference  to
     Exhibit 10.12 to the Company's 1992 Form 10-K).

10.13      Second  Amendment to the Amended and Restated  General
     Partnership Agreement for Coso Power Developers between Coso
     Technology  Corporation and Caithness  Navy  II  Group  L.P.
     dated as of December 16, 1992 (incorporated by reference  to
     Exhibit 10.13 to the Company's 1992 Form 10-K).

10.14      Form  of  Amended  and Restated  Field  Operation  and
     Maintenance  Agreement between Coso Joint Ventures  and  the
     Company  dated  as  of  December 16, 1992  (incorporated  by
     reference to Exhibit 10.14 of the Company's 1992 Form 10-K).

10.15      Form  of  Amended and Restated Project  Operation  and
     Maintenance  Agreement between Coso Joint  Venture  and  the
     Company  dated  as  of  December 16, 1992  (incorporated  by
     reference to Exhibit 10.15 to the Company's 1992 Form 10-K).

10.16      Trust Indenture between Coso Funding Corp. and Bank of
     America National Trust and Savings Association dated  as  of
     December 16 1992 (incorporated by reference to Exhibit 10.16
     to the Company's 1992 Form 10-K).
10.17      Form  of Amended and Restated Credit Agreement between
     Coso  Funding  Corp.  and Coso Joint Ventures  dated  as  of
     December  16,  1992  (incorporated by reference  to  Exhibit
     10.17 to the Company's 1992 Form 10-K).

10.18      Form  of  Support  Loan  Agreement  among  Coso  Joint
     Ventures  dated December 16, 1992 (incorporated by reference
     to Exhibit 10.18 to the Company's 1992 Form 10-K).

10.19      Form  of  Project Loan Pledge Agreement  between  Coso
     Joint  Ventures  and  Bank  of America  National  Trust  and
     Savings  dated  as  of  December 16, 1992  (incorporated  by
     reference to Exhibit 10.19 to the Company's 1992 Form 10-K).

10.20      Power  Purchase Contracts between Southern  California
     Edison Company and:
          (a)   China Lake Joint Venture, executed June  4,  1984
          with a term of 24 years;
          (b)   China  Lake Joint Venture, executed  February  1,
          1985 with a term of 23 years; and
          (c)  Coso Geothermal Company, executed February 1, 1985
          with  a term of 30 years (incorporated by reference  to
          Exhibit 10.7 to the Company's Registration Statement on
          Form S-1, 33-7770).

10.21     Contract No. N62474-79-C-5382 between the United States
     of  America  and China Lake Joint Venture, restated  October
     19,  1983  as "Modification P00004," including modifications
     through "Modification P00026", dated December 16, 1992  (the
     "Navy  Contract")(incorporated by reference to Exhibit 10.21
     to the Company's 1992 Form 10-K).

10.22      Modification  to Contract No. P00028, dated  June  28,
     1993, Modification to Contract No. P00029, dated October  4,
     1994 and Modification to Contract No. P00031, dated December
     19,  1994  all amending the Navy Contract "(incorporated  by
     reference  to Exhibit 10.22 to the Company's 1994  Form  10-
     K)."

10.23      Lease between the BLM and Coso Land Company, effective
     November  1, 1985 (with Designation of Geothermal  Operator)
     (incorporated by reference to Exhibit 10.8 to the  Company's
     Registration Statement on Form S-1, 33-7770).

10.24     Stock Purchase Agreement between the Company and Kiewit
     Energy Company dated as of February 18, 1991, as amended  as
     of  June 19, 1991 (incorporated by reference to Exhibit 1 to
     the Company's Form 8-K dated February 26, 1991).

10.25      Amendment  No.  2 to Stock Purchase Agreement  between
     Kiewit Energy Company and the Company dated as of January 8,
     1992  (incorporated  by reference to Exhibit  10.24  to  the
     Company's 1992 Form 10-K).

10.26      Amendment  No.  3 to Stock Purchase Agreement  between
     Kiewit  Energy Company and the Company dated as of April  2,
     1993  (incorporated  by reference to Exhibit  10.25  to  the
     Company's 1993 Form 10-K).

10.27      Shareholders Agreement between the Company and  Kiewit
     Energy Company dated as of February 18, 1991, as amended  as
     of  June  19, 1991 and as of November 20, 1991 (incorporated
     by  reference to Exhibit 1 to the Company's Form  8-K  dated
     February 26, 1991, Exhibit 1 to the Company's Form 8-K dated
     July 18, 1992, and Exhibit 3 to the Company's Form 8-K dated
     November 23, 1991).

10.28      Amendment No. 3 to Shareholder's Agreement between the
     Company and Kiewit Energy Company dated as of April 2,  1993
     (incorporated  by reference to Exhibit 14 to  the  Company's
     Form 8-A).
10.29      Amendment No. 4 to Shareholder's Agreement between the
     Company and Kiewit Energy Company dated as of July 20,  1993
     (incorporated by reference to Exhibit 10.28 to the Company's
     1993 Form 10-K).

10.30      Registration Rights Agreement between the Company  and
     Kiewit  Energy  Company dated as of February  18,  1991,  as
     amended  as  of June 19, 1991 (incorporated by reference  to
     Exhibit 1 to the Company's Form 8-K dated February 26, 1991,
     and  Exhibit  1  to the Company's Form 8-K  dated  July  18,
     1992).

10.31      Registration Rights Agreement between the Company  and
     Kiewit  Energy  Company  dated June  19,  1991,  as  amended
     November 20, 1991 (incorporated by reference to Exhibit 1 of
     the Company's Form 8-K dated June 19, 1991 and Exhibit 4  to
     the Company's Form 8-K dated November 21, 1991).

10.32      Stock  Option Agreement between the Company and Kiewit
     Energy Company dated as of February 18, 1991, as amended  as
     of  June 19, 1991 (incorporated by reference to Exhibit 1 to
     the  Company's Form 8-K dated February 26, 1991, and Exhibit
     1 to the Company's Form 8-K dated July 18, 1992).

10.33      Amendment No. 2 to Stock Option Agreement between  the
     Company  and Kiewit Energy Company dated as of May 12,  1994
     (incorporated by reference to Exhibit 10.33 to the Company's
     1995 Form 10-K).

10.34      Stock  Option Agreement between the Company and Kiewit
     Energy  Company  dated as of June 19, 1991 (incorporated  by
     reference to Exhibit 1 to the Company's Form 8-K dated  July
     18, 1991).

10.35      Securities Purchase Agreement between the Company  and
     Kiewit  Energy  Company  dated  as  of  November  20,   1991
     (incorporated  by  reference to Exhibit 2 to  the  Company's
     Form 8-K dated November 21, 1991).

10.36       1996   Employee   Stock  Option  Plan,   as   amended
     (incorporated  by  reference to Exhibit A to  the  Company's
     1996 Proxy Statement).

10.37      1994  Employee  Stock Purchase Plan  (incorporated  by
     reference   to  Exhibit  A  to  the  Company's  1994   Proxy
     Statement).

10.38      Indenture  between the Company and The Chemical  Trust
     Company   of   California  dated  as  of   June   24,   1993
     (incorporated by reference to the Company's Form  8-K  dated
     June 24, 1993, File No. 1-9874).

10.39     Registration Rights Agreement among the Company, Lehman
     Brothers, Inc. and Alex Brown & Sons Incorporated dated June
     24, 1993 (incorporated by reference to the Company's Form 8-
     K dated June 24, 1993, File No. 1-9874).

10.40      Indenture dated March 24, 1994 between the Company and
     IBJ  Schroder  Bank  and  Trust  Company  (incorporated   by
     reference to Exhibit 3 to the Company's Form 8-K dated March
     28, 1994).

10.41      Amended and Restated Employment Agreement between  the
     Company  and  David  L. Sokol dated as of  August  21,  1995
     (incorporated by reference to Exhibit 10.82 to the Company's
     1995 Form 10-K).

10.42     Restricted Stock Exchange Agreement between the Company
     and   David  L.  Sokol  dated  as  of  November   29,   1995
     (incorporated by reference to Exhibit 10.43 to the Company's
     1995 Form 10-K).

10.43      Amendment No. 1 to the Amended and Restated Employment
     Agreement  between  the Company and David  L.  Sokol,  dated
     August 28, 1996.

10.44     Employment Agreement between the Company and Gregory E.
     Abel, dated August 6, 1996.

10.45      Employment Agreement between the Company and  John  G.
     Sylvia, dated August 6, 1996.

10.46      Employment Agreement between the Company and Steven A.
     McArthur, dated August 6, 1996.

10.47      Standard  Offer  Number 2, Standard  Offer  for  Power
     Purchase  with a Firm Capacity Qualifying Facility effective
     June  15,  1990  ("SO2") between San Diego  Gas  &  Electric
     Company and Bonneville Pacific Corporation (incorporated  by
     reference to Exhibit 10.42 to the Company's 1993 Form 10-K).

10.48      Amendment  Number One to the SO2 dated  September  25,
     1990  (incorporated  by reference to Exhibit  10.43  to  the
     Company's 1993 Form 10-K).

10.49      Joint  Venture  Agreement among  the  Company,  Kiewit
     Diversified  Group Inc. and Kiewit Construction  Group  Inc.
     dated  December  14,  1993  (incorporated  by  reference  to
     Exhibit 10.44 to the Company's 1993 Form 10-K).

10.50      Joint Venture Agreement between the Company and Kiewit
Diversified Group Inc., dated December  4, 1996.

10.51      Agreement  and Plan of Merger between the Company,  CE
     Acquisition Company, Inc. and Magma dated December  5,  1994
     (incorporated by reference to (c)(3) to Exhibit 99.1 to  the
     Company's  Current  Report on Form  8-K  dated  December  9,
     1994).

10.52      Stock  Purchase  Agreement between CalEnergy  Imperial
     Valley Company, Inc. and Edison Mission Energy, dated as  of
     March  27, 1996 (incorporated by reference to Exhibit  10.50
     to the Company's 1995 Form 10-K).

10.53     Standard Offer No. 4 Power Purchase Agreement (Elmore),
     dated  June  15,  1984, between Southern  California  Edison
     Company and Magma Electric Company including Amendments  No.
     1  and No. 2 (incorporated by reference to Exhibit 10.14  to
     Magma  Power  Company's  Amendment  No.  1  to  Registration
     Statement Form S-4 dated February 2, 1988, ("Magma 1988 Form
     S-4")).

10.54      Standard  Offer  No. 4 Power Purchase  Agreement  (Del
     Ranch)  dated February 22, 1984, between Southern California
     Edison  Company  and Imperial Energy Corporation,  including
     Amendments  No.  1 and No. 2 (incorporated by  reference  to
     Exhibit 10.15 to the Magma 1988 Form S-4).

10.55     Standard Offer No. 4 Power Purchase Agreement (Vulcan),
     dated  June  15,  1984, between Southern  California  Edison
     Company and Magma Electric Company including Amendment No. 1
     (incorporated  by reference to Exhibit 10.16  to  the  Magma
     1988 Form S-4).

10.56      Standard  Offer No. 4 Power Purchase Agreement  (River
     Ranch),  dated  April 16, 1985, between Southern  California
     Edison  Company  and Imperial Energy Corporation,  including
     Amendment No. 1 (incorporated by reference to Exhibit  10.20
     to the Magma 1988 Form S-4).

10.57      Partnership  Agreement dated August 30,  1985  between
     Vulcan  Power  Company and BN Geothermal, Inc. (incorporated
     by  reference to Exhibit 10.88 to the Magma Power  Company's
     Form  8  Amendment (dated December 18, 1990) to Magma  Power
     Company's  Form  10-K for the year ended December  31,  1989
     ("Magma Form 8")).

10.58      Amended and Restated Limited Partnership Agreement  of
     Del  Ranch,  Ltd.,  a California Limited Partnership,  dated
     March  14, 1988 by and among Red Hill Geothermal,  Inc.  and
     Conejo Energy Company, as General Partners, and Magma  Power
     Company  and  Conejo  Energy Company,  as  Original  Limited
     Partners (incorporated by reference to Exhibit 10.53 to  the
     Magma Power Company Annual Report on Form 10-K for the  year
     ended December 31, 1987, File No. 0-10533 ("1987 Magma  Form
     10-K")).

10.59      Limited Partnership Agreement of Leathers, L.P., dated
     August  15, 1988 by and among Red Hill Geothermal, Inc.  and
     San  Felipe Energy Company, as General Partners,  and  Magma
     Power  Company  and  San Felipe Energy Company,  as  Limited
     Partners (incorporated by reference to Exhibit 10.79 to  the
     Magma Power Company Annual Report on Form 10-K for the  year
     ended December 31, 1988, File No. 0-10533 ("1988 Magma  Form
     10-K")).

10.60      Amended and Restated Limited Partnership Agreement  of
     Elmore, Ltd., a California Limited Partnership, dated  March
     14,  1988 by and among Red Hill Geothermal, Inc. and  Niguel
     Energy Company, as General Partners, and Magma Power Company
     and  Niguel  Energy Company, as  Original  Limited  Partners
     (incorporated  by  reference to Exhibit 10.55  to  the  1987
     Magma Form 10-K).

10.61      Operating  and Maintenance Agreement dated  March  14,
     1988 by and between Red Hill Geothermal, Inc. and Del Ranch,
     Ltd.,  a  California  Limited Partnership  (incorporated  by
     reference to Exhibit 10.56 to the 1987 Magma Form 10-K).

10.62      First Amendment to Operating and Maintenance Agreement
     dated as of April 14, 1989 between Red Hill Geothermal, Inc.
     and Del Ranch L.P. and the Second Amendment to the Operating
     and    Maintenance   Agreement   dated   April   18,    1990
     "(incorporated  by  reference  to  Exhibit  10.60   to   the
     Company's  Form 10-K/A Amendment (dated March 31,  1995)  to
     the Company's 1994 Form 10-K)."

10.63      Operating  and Maintenance Agreement dated August  15,
     1988  by and between Red Hill Geothermal, Inc. and Leathers,
     L.P. (incorporated by reference to Exhibit 10.84 to the 1988
     Magma Form 10-K).

10.64      First Amendment to Operating and Maintenance Agreement
     dated as of April 14, 1989 between Red Hill Geothermal, Inc.
     and Leathers, L.P. and the Second Amendment to the Operating
     and    Maintenance   Agreement   dated   April   18,    1990
     "(incorporated  by  reference  to  Exhibit  10.62   to   the
     Company's 1994 Form 10-K)."

10.65      Operating  and Maintenance Agreement dated  March  14,
     1988  by  and between Red Hill Geothermal, Inc. and  Elmore,
     Ltd.,  a  California  Limited Partnership  (incorporated  by
     reference to Exhibit 10.57 to the 1987 Magma Form 10-K).

10.66      First  Amendment  to  the  Operating  and  Maintenance
     Agreement  dated  as  of  April 14, 1988  between  Red  Hill
     Geothermal,  Inc.  and  Elmore, Ltd., a  California  Limited
     Partnership  and the Second Amendment to the  Operating  and
     Maintenance Agreement dated April 18, 1990 "(incorporated by
     reference  to Exhibit 10.64 to the Company's 1994  Form  10-
     K)."

10.67      Brine  Sales  Agreement dated August 30, 1985  between
     Vulcan  Power Company and Vulcan/BN Geothermal Power Company
     (incorporated  by reference to Exhibit 10.90  to  the  Magma
     Power Company Form 8 Amendment (dated December 18, 1990)  to
     the  Magma  Power  Company  Form 10-K  for  the  year  ended
     December 31, 1989).

10.68      Easement Grant Deed and Agreement Regarding Rights for
     Geothermal  Development dated March 14, 1988 by and  between
     Magma  Power  Company  and  Del Ranch,  Ltd.,  a  California
     Limited  Partnership (incorporated by reference  to  Exhibit
     10.58 to the 1987 Magma Form 10-K).

10.69      Easement Grant Deed and Agreement Regarding Rights for
     Geothermal Development dated August 15, 1988 by and  between
     Magma  Power  Company  and Leathers, L.P.  (incorporated  by
     reference to the 1988 Magma Form 10-K).

10.70      Easement Grant Deed and Agreement Regarding Rights for
     Geothermal  Development dated March 14, 1988 by and  between
     Magma  Power Company and Elmore, Ltd., a California  Limited
     Partnership (incorporated by reference to Exhibit  10.59  to
     the 1987 Magma Form 10-K).

10.71      Administrative Services Agreement dated March 14, 1988
     by  and  between  Red Hill Geothermal, Inc. and  Del  Ranch,
     Ltd.,  a  California  Limited Partnership  (incorporated  by
     reference to the 1987 Magma Form 10-K).

10.72     Administrative Services Agreement dated August 15, 1988
     by  and between Red Hill Geothermal, Inc. and Leathers, L.P.
     (incorporated  by  reference to Exhibit 10.82  to  the  1988
     Magma Form 10-K).

10.73      Administrative Services Agreement dated March 14, 1988
     by and between Red Hill Geothermal Inc. and Elmore, Ltd.,  a
     California Limited Partnership (incorporated by reference to
     Exhibit 10.63 to the 1987 Magma Form 10-K).

10.74     Amended and Restated Credit Agreement dated as of April
     18,   1990  among  Del  Ranch,  Ltd.  a  California  Limited
     Partnership,  the Banks Listed therein, and Morgan  Guaranty
     Trust  Company  of  New  York,  as  Agent  (incorporated  by
     reference to Exhibit 10.72 to the Company's 1994 Form 10-K).

10.75      LOC Debt Facility Agreement dated as of April 18, 1990
     among Del Ranch, Ltd., a California Limited Partnership, the
     Banks  listed therein, Morgan Guaranty Trust Company of  New
     York  as  the  Agent  and Fuji Bank,  Limited,  Los  Angeles
     Agency,  as  Fronting  Bank (incorporated  by  reference  to
     Exhibit 10.73 to the Company's 1994 Form 10-K).

10.76      Security  Agreement dated March  14,  1988  among  Del
     Ranch,   Ltd.,  a  California  Limited  Partnership,  Morgan
     Guaranty  Trust  Company of New York, as Agent  for  and  on
     behalf  of the Banks, Morgan Guaranty Trust Company  of  New
     York,  and  Morgan Guaranty Trust Company of  New  York,  as
     Security Agent (incorporated by reference to the 1987  Magma
     Form 10-K).

10.77      Amendment Number One to Security Agreement dated as of
     April  14,  1989, and Amendment Number Two to  the  Security
     Agreement  dated  April 18, 1990 among Del  Ranch,  Ltd.,  a
     California   Limited  Partnership,  Morgan  Guaranty   Trust
     Company  of  New  York, as Agent for and on  behalf  of  the
     Banks,  Morgan Guaranty Trust Company of New York and Morgan
     Guaranty  Trust  Company  of  New  York  as  Security  Agent
     (incorporated by reference to Exhibit 10.75 to the Company's
     1994 Form 10-K).

10.78      Deed of Trust, Assignment of Rents, Security Agreement
     and  Fixture Filing Construction Deed of Trust dated  as  of
     March  14, 1988 among Del Ranch, Ltd., a California  Limited
     Partnership,  Ticor Title Insurance Company  of  California,
     and  Morgan  Guaranty Trust Company of New York as  Security
     Agent (incorporated by reference to the 1987 Magma Form  10-
     K).

10.79      First Amendment to the Deed of Trust, dated April  18,
     1990  between  Del  Ranch, Ltd. and  Morgan  Guaranty  Trust
     Company  of  New York (incorporated by reference to  Exhibit
     10.77 to the Company's 1994 Form 10-K).

10.80     Amended and Restated Credit Agreement dated as of April
     18,   1990   among   Elmore,  Ltd.,  a  California   Limited
     Partnership,  the Banks Listed therein, and Morgan  Guaranty
     Trust  Company  of  New  York,  as  Agent  (incorporated  by
     reference to Exhibit 10.78 to the Company's 1994 Form 10-K).

10.81      LOC Debt Facility Agreement dated as of April 18, 1990
     among  Elmore,  Ltd., a California Limited Partnership,  the
     Banks  listed therein, Morgan Guaranty Trust Company of  New
     York as Agent and Fuji Bank, Limited, Los Angeles Agency, as
     Fronting  Bank (incorporated by reference to Exhibit   10.79
     to the Company's 1994 Form 10-K).

10.82      Security Agreement dated March 14, 1988 among  Elmore,
     Ltd.,  a  California  Limited Partnership,  Morgan  Guaranty
     Trust Company of New York, as Agent for and on behalf of the
     Banks, Morgan Guaranty Trust Company of New York, and Morgan
     Guaranty  Trust  Company  of New  York,  as  Security  Agent
     (incorporated  by  reference to Exhibit 10.71  to  the  1987
     Magma Form 10-K).

10.83      Amendment Number One to Security Agreement dated as of
     April  14,  1989 among Elmore Ltd and Morgan Guaranty  Trust
     Company  of  New York and Amendment Number Two  to  Security
     Agreement  dated April 18, 1990 among Elmore,  L.P.,  Morgan
     Guaranty  Trust Company of New York, as Agent, on behalf  of
     the Banks (incorporated by reference to Exhibit 10.81 to the
     Company's 1994 Form 10-K).

10.84      Deed of Trust, Assignment of Rents, Security Agreement
     and  Fixture Filing Construction Deed of Trust dated  as  of
     March  14,  1988  among Elmore, Ltd., a  California  Limited
     Partnership, Ticor Title
     Insurance  Company of California, and Morgan Guaranty  Trust
     Company  of  New  York  as Security Agent  (incorporated  by
     reference to Exhibit 10.73 to the 1987 Magma Form 10-K).

10.85      First Amendment to Deed of Trust dated April 18,  1990
     between  Elmore, Ltd. and Morgan Guaranty Trust  Company  of
     New  York,  as Security Agent (incorporated by reference  to
     Exhibit  10.83 to the Company's 1994 Form 10-K).

10.86      Amended and Restated Credit Agreement dated April  18,
     1990  among  Leathers L.P. and the Banks listed therein  and
     Morgan   Guaranty  Trust  Company  of  New  York  as   Agent
     (incorporated by reference to Exhibit 10.84 to the Company's
     1994 Form 10-K).

10.87      Security Agreement dated March 14, 1988 among Leathers
     L.P.,  a  California  Limited Partnership,  Morgan  Guaranty
     Trust Company of New York, as Agent for and on behalf of the
     Banks, Morgan Guaranty Trust Company of New York, and Morgan
     Guaranty  Trust  Company  of New York,  as  Security  Agent,
     Amendment Number One to Security Agreement dated as of April
     14,  1989  and  Amendment Number Two to  Security  Agreement
     dated  as  of  April 18, 1990 (incorporated by reference  to
     Exhibit 10.85 to the Company's 1994 Form 10-K).

10.88      Deed of Trust, Assignment of Rents, Security Agreement
     and  Fixture Filing Construction Deed of Trust dated  as  of
     March  14,  1988 among Leathers, L.P., a California  Limited
     Partnership,  Ticor Title Insurance Company  of  California,
     and  Morgan  Guaranty Trust Company of New York as  Security
     Agent  and First Amendment to Deed of Trust dated April  18,
     1990  (incorporated  by reference to Exhibit  10.85  to  the
     Company's 1994 Form 10-K).

10.89      LOC Debt Facility Agreement dated as of April 18, 1990
     among Leathers, L.P., a California Limited Partnership,  the
     Banks  listed therein, Morgan Guaranty Trust Company of  New
     York as Agent and Fuji Bank, Limited, Los Angeles Agency, as
     Fronting Bank (incorporated by reference to Exhibit 10.87 to
     the Company's 1994 Form 10-K).

10.90      Loan  Agreement  dated as of October 1,  1990  between
     California Pollution Control Financing Authority and  Desert
     Valley Company, relating to the California Pollution Control
     Financing  Authority Pollution Control Revenue  Bonds  Small
     Business  Series  1990-A  (the  "$4,000,000  Monofill   Bond
     Financing") (incorporated by reference to Exhibit  10.92  to
     the  Magma  Power  Company  Form 10-K  for  the  year  ended
     December 31, 1990, File No. 0-10533 (the "1990 Magma Form 10-
     K")).

10.91      Master Reimbursement Agreement dated as of October  1,
     1990,   by  and  among  the  California  Pollution   Control
     Financing  Authority, Desert Valley Company  and  the  Sanwa
     Bank,   Limited,  Los  Angeles  Branch,  relating   to   the
     $4,000,000   Monofill   Bond  Financing   (incorporated   by
     reference to Exhibit 10.93 to the 1990 Magma Form 10-K).

10.92      Sale  and Purchase Agreement between Union Oil Company
     of  California  and  Magma  Power Company  effective  as  of
     December  31,  1992  (incorporated by reference  to  Exhibit
     10.97 to the Magma Power Company Form 8 dated June 2, 1993).

10.93      Contract  for the Purchase and Sale of Electric  Power
     (Unit  I) from the Salton Sea Geothermal Generating Facility
     between Southern California Edison Company and Earth Energy,
     Inc.,  dated May 8, 1987, including Amendment No. 1 to  such
     contract, dated March 30, 1993 (incorporated by reference to
     Exhibit 10.101 to the Magma Power Company Form 10-K for  the
     year  ended December 31, 1993, File No. 0-10533, (the  "1993
     Magma Form 10-K")).

10.94      Power  Purchase  Contract (Unit  II)  by  and  between
     Southern   California   Edison  Company   and   Westmoreland
     Geothermal  Associates,  dated  April  16,  1985,  including
     Amendment  No. 1 to such contract, dated December  18,  1987
     (incorporated  by reference to Exhibit 10.102  to  the  1993
     Magma Form 10-K).

10.95      Power  Purchase  Contract (Unit III) between  Southern
     California  Edison Company and Union Oil Company Salton  Sea
     III, dated April 16, 1985 (incorporated by reference to  the
     1993 Magma Form 10-K).

10.96      Consolidated,  Amended  and  Restated  Power  Purchase
     Agreement  (Unit  IV)  between  Southern  California  Edison
     Company  and  Fish Lake Power Company and Salton  Sea  Power
     Generation, L.P. (incorporated by reference to Exhibit  10.9
     to  the  Registration Statement on Form S-4 dated August  9,
     1995   of  Salton  Sea  Funding  Corporation  33-95538  (the
     "Funding Corporation S-4").

10.97     125 MW Power Plant - Upper Mahiao Agreement (the "Upper
     Mahiao  ECA")  dated  September 6, 1993 between  PNOC-Energy
     Development  Corporation ("PNOC-EDC")  and  Ormat,  Inc.  as
     amended  by the First Amendment to 125 MW Power Plant  Upper
     Mahiao  Agreement dated as of January 28, 1994,  the  Letter
     Agreement  dated  February 10, 1994,  the  Letter  Agreement
     dated  February 18, 1994 and the Fourth Amendment to 125  MW
     Power  Plant - Upper Mahiao Agreement dated as of  March  7,
     1994  (incorporated  by reference to Exhibit  10.95  to  the
     Company's 1994 Form 10-K).

10.98      Credit  Agreement dated April 8, 1994  among  CE  Cebu
     Geothermal  Power Company, Inc., the Banks  thereto,  Credit
     Size as Agent (incorporated by reference to Exhibit 10.96 to
     the Company's 1994 Form 10-K).

10.99      Credit Agreement dated as of April 8, 1994 between  CE
     Cebu  Geothermal Power Company, Inc., Export-Import Bank  of
     the  United  States  (incorporated by reference  to  Exhibit
     10.97 to the Company's 1994 Form 10-K).

10.100     Pledge  Agreement among CE Philippines Ltd, Ormat-Cebu
     Ltd.,  Credit  Suisse  as  Collateral  Agent  and  CE   Cebu
     Geothermal  Power Company, Inc. dated as of  April  8,  1994
     (incorporated by reference to Exhibit 10.98 to the Company's
     1994 Form 10-K).

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

10.102      180   MW   Power   Plant   -  Mahanagdong   Agreement
     ("Mahanagdong  ECA") dated September 18, 1993 between  PNOC-
     EDC  and CE Philippines Ltd. and the Company, as amended  by
     the  First Amendment to Mahanagdong ECA dated June 22, 1994,
     the  Letter  Agreement  dated  July  12,  1994,  the  Letter
     Agreement  dated July 29, 1994, and the Fourth Amendment  to
     Mahanagdong  ECA  dated  March  3,  1995  (incorporated   by
     reference to Exhibit 10.100 to the Company's 1994  Form  10-
     K).

10.103     Credit  Agreement dated as of June 30, 1994  among  CE
     Luzon  Geothermal  Power  Company,  Inc.,  American  Pacific
     Finance  Company,  the Lenders party thereto,  and  Bank  of
     America   National   Trust   and  Savings   Association   as
     Administrative Agent (incorporated by reference  to  Exhibit
     10.101 to the Company's 1994 Form 10-K).

10.104     Credit Agreement dated as of June 30, 1994 between  CE
     Luzon Geothermal Power Company, Inc. and Export-Import  Bank
     of  the  United States (incorporated by reference to Exhibit
     10.102 to the Company's 1994 Form 10-K).

10.105     Finance Agreement dated as of June 30, 1994 between CE
     Luzon  Geothermal  Power Company, Inc. and Overseas  Private
     Investment Corporation (incorporated by reference to Exhibit
     10.103 to the Company's 1994 Form 10-K).

10.106     Pledge  Agreement dated as of June 30, 1994  among  CE
     Mahanagdong  Ltd.,  Kiewit  Energy  International  (Bermuda)
     Ltd., Bank of America National Trust and Savings Association
     as  Collateral Agent and CE Luzon Geothermal Power  Company,
     Inc.  (incorporated by reference to Exhibit  10.104  to  the
     Company's 1994 Form 10-K).

10.107     Overseas  Private Investment Corporation  Contract  of
     Insurance dated July 29, 1994 between OPIC and the  Company,
     CE  International  Ltd., CE Mahanagdong  Ltd.  and  American
     Pacific Finance Company and Amendment No. 1 dated August  3,
     1994  (incorporated by reference to Exhibit  10.105  to  the
     Company's 1994 Form 10-K).

10.108     231  MW  Power  Plant - Malitbog Agreement  ("Malitbog
     ECA")  dated September 10, 1993 between PNOC-EDC  and  Magma
     Power  Company  and the First and Second Amendments  thereto
     dated  December  8,  1993 and March 10,  1994,  respectively
     (incorporated  by  reference  to  Exhibit  10.106   to   the
     Company's 1994 Form 10-K).

10.109     Credit  Agreement dated as of November 10, 1994  among
     Visayas Power Capital Corporation, the Banks parties thereto
     and  Credit Suisse Bank Agent (incorporated by reference  to
     Exhibit 10.107 to the Company's 1994 Form 10-K).

10.110    Finance Agreement dated as of November 10, 1994 between
     Visayas   Geothermal  Power  Company  and  Overseas  Private
     Investment Corporation (incorporated by reference to Exhibit
     10.108 to the Company's 1994 Form 10-K).

10.111     Pledge and Security Agreement dated as of November 10,
     1994 among Broad Street Contract Services, Inc., Magma Power
     Company,  Magma Netherlands B.V. and Credit Suisse  as  Bank
     Agent  (incorporated by reference to Exhibit 10.109  to  the
     Company's 1994 Form 10-K).

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

10.113      Agreement   as  to  Certain  Common  Representations,
     Warranties,  Covenants and Other Terms, dated  November  10,
     1994 between Visayas Geothermal Power Company, Visayas Power
     Capital Corporation, Credit Suisse, as Bank Agent, OPIC  and
     the  Banks  named  therein  (incorporated  by  reference  to
     Exhibit 10.111 to the Company's 1994 Form 10-K).

10.114     Indenture dated as of July 21, 1995 between Salton Sea
     Funding  Corporation  ("Funding Corporation")  and  Chemical
     Trust  Company of California (incorporated by  reference  to
     Exhibit 4.1(a) to the Funding Corporation Form S-4).

10.115     First  Supplemental Indenture dated as of October  18,
     1995  between Funding Corporation and Chemical Trust Company
     of  California (incorporated by reference to Exhibit  4.1(b)
     to the Funding Corporation Form S-4).

10.116     Indenture dated July 1995 between the Company and  The
     Bank of New York (incorporated by reference to the Company's
     Amendment No. 1 to Registration Statement on Form S-3  dated
     May 17, 1995).

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

10.118     Modification to Contract No. P00019 dated   August  1,
     1995,  Modification to Contract No. P00020 dated  August  1,
     1995, Modification to Contract No. P00034 dated February  8,
     1995  and Modification to Contract No. P00035 dated February
     8, 1995, amending the Navy Contract.

10.119     Plant Connection Agreement between Imperial Irrigation
     District and Salton Sea Power Generation L.P. and Fish  Lake
     Power   Company  dated  July  14,  1995  (incorporation   by
     reference to Exhibit 10.15 to the Funding Corporation S-4).

10.120      Transmission  Services  Agreement  between   Imperial
     Irrigation District and Salton Sea Power Generation L.P. and
     Fish Lake Power Company dated July 14, 1995 (incorporated by
     reference to Exhibit 10.17 to the Funding Corporation S-4).

10.121     Second  Amended  and Restated Administrative  Services
     Agreement  among  CalEnergy Operation  Company,  Salton  Sea
     Brine Processing L.P., Salton Sea Power Generation L.P.  and
     Fish Lake Power Company dated July 15, 1995 (incorporated by
     reference to Exhibit 10.20 to the Funding Corporation S-4).

10.122     Second  Amended and Restated Operating and Maintenance
     Agreement  among  Magma  Power  Company,  Salton  Sea  Brine
     Processing L.P., Salton Sea Power Generation L.P., and  Fish
     Lake  Power  Company  dated July 15, 1995  (incorporated  by
     reference to Exhibit 10.21 to the Funding Corporation S-4).

10.123    Amended and Restated Casecnan Project Agreement between
     the National Irrigation Administration and CE Casecnan Water
     and Energy Company Inc. dated June 26, 1995 (incorporated by
     reference to Exhibit 10.1 to the Casecnan Form S-4).

10.124     Stock Purchase Agreement, dated as of July 3, 1996, by
     and among CE/FS Holding Company, Inc., David H. Dewhurst and
     all  remaining  owners of capital stock of  Falcon  Seaboard
     Resources,  Inc. (incorporated by reference to Exhibit  99.1
     to  the Company's Form 8-K, dated July 8, 1996, File No.  1-
     9874).

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

10.126     Indenture, dated as of September 20, 1996, between the
     Company  and IBJ Schroder Bank & Trust Company, as  trustee,
     relating  to $225,000,000 principal amount of 9 1/4%  Senior
     Notes due 2006 (incorporated by reference to Exhibit 4.1  to
     the   Company's   Registration  Statement   on   Form   S-3,
     Registration No. 333-15591).

10.127     Second  Supplemental Indenture, dated as of  June  20,
     1996,  between  Chemical  Trust Company  of  California  and
     Funding  Corporation (incorporated by reference  to  Exhibit
     4.1(c)  to  Amendment  No.  1 to the  Funding  Corporation's
     Registration  Statement on Form S-4, Registration  No.  333-
     07527 ("Funding Corp. II S-4").

10.128     Third  Supplemental Indenture, between Chemical  Trust
     Company   of   California   and  the   Funding   Corporation
     (incorporated by reference to Exhibit 4.1(d) to the  Funding
     Corp. II S-4).

10.129      Indenture   for   the  6  1/4%   Convertible   Junior
     Subordinated  Debentures due 2012, dated as of February  26,
     1997,  between the Company, as issuer, and the Bank  of  New
     York, as Trustee.

10.130    Term Loan and Revolving Facility Agreement, dated as of
     October 28, 1996, among CE Electric UK Holdings, CE Electric
     UK plc and Credit Suisse.*

10.131    Public Electricity Supply License*

10.132     Second Tier Supply Licenses to Supply Electricity  for
     England & Wales and Scotland.*

10.133     Pooling  and Settlement Agreement for the  Electricity
     Industry  in  England and Wales dated 30th March,  1990  (as
     amended at 17th October, 1996), among the Generators  (named
     therein),  the Suppliers (named therein), Energy Settlements
     and  Information  Services  Limited  (as  Settlement  System
     Administrator), Energy Pool Funds Administration Limited (as
     Pool  Funds  Administrator), Scottish Power plc, Electricite
     De France, Service National and Others.*

10.134    Master Connection and User System Agreement with The National
     Grid Company plc.*

10.135    Gas Suppliers License dated February 21, 1996.*

10.136    First Supplemental Trust Indenture dates as of February
     18,  1997  between  Coso Funding Corp. and  First Bank,
     National  Association  (successor  to  Bank  of
     America Nation Trust and Savings Association).*

10.137     Form  First  Amendment to Amended and Restated  Credit
     Agreement, dated February 18, 1997, between First  Bank,
     National  Association  (as  successor  to  Coso
     Funding Corp.) and the Coso Joint Ventures.*

10.138    Omnibus Acknowledgment and Agreement dated February 18,
     1997  between  Coso Funding Corp., the Coso Joint  Ventures,
     First Bank, National Association and others.*

11.0 Calculation  of  Earnings  Per  Share  in  accordance   with
     Interpretive Release No. 34-9083.

13.0 The  Company's 1996 Annual Report (only the portions thereof
     specifically  incorporated herein by  reference  are  deemed
     filed herewith).

21.0 Subsidiaries of Registrant.

23.0 Consent of Independent Auditors.

24.0 Power of Attorney.

27.0 Financial Data Schedule.


*Denotes documents to be filed with an amendment to Form 10-K.