SELECTED Financial Data
Dollars in Thousands Except Per Share Amounts
<TABLE>
<CAPTION>
                                                                          Year Ended December 31,                   

                                                       1995 1          1994          1993          1992         1991

<S>                                                <C>           <C>           <C>           <C>   
Sales of electricity                                 $332,732      $152,047      $129,861      $115,087     $104,155
Sales of steam                                          2,898         2,515         2,198         2,255        2,029
Royalties                                              19,482           ---           ---           ---          ---
Other income                                           43,611        31,292        17,194        10,187        9,379
Expenses                                              301,672       130,018        87,995        76,797       80,697
Income before provision for
     income taxes                                      97,051        55,836        61,258        50,732       34,866
Income before change in accounting
     principle and extraordinary item                  66,420        38,834        43,074        38,810       26,582
Cumulative effect of change in 
     accounting principle2                                ---           ---         4,100           ---          ---
Minority interest                                       3,005           ---           ---           ---          ---
Extraordinary item3                                       ---       (2,007)           ---       (4,991)          ---
Net income before preferred dividends                  63,415        36,827        47,174        33,819       26,582
Preferred dividends                                     1,080         5,010         4,630         4,275          ---
Income per share before change in accounting
     principle and extraordinary item                    1.25           .95          1.00           .92          .75
Cumulative effect of change in accounting
     principle per share                                  ---           ---           .11           ---          ---
Extraordinary item per share                              ---         (.06)           ---         (.13)          ---
Net income per share - primary                           1.25           .89          1.11           .79          .75
Total assets                                        2,654,038     1,131,145       715,984       580,550      517,994
Total liabilities                                   2,084,474       867,703       425,393       336,272      298,146
Deferred income                                        26,032        19,851        20,288        21,164       22,015
Redeemable preferred stock                                ---        63,600        58,800        54,350       54,705
 Stockholders' equity                                 543,532       179,991       211,503       168,764      143,128
Common stock cash dividends                               ---           ---           ---           ---          ---
</TABLE>


1 Reflects acquisition of Magma. See Note 3 to the financial statements.
2 See Note 14 to the consolidated financial statements.
3 See Note 20 to the consolidated financial statements.
<PAGE>
MANAGEMENT'S Discussion and Analysis of Financial Condition 
and Results of Operations
Dollars and Shares in Thousands Except Per Share Data

The following is management's discussion and analysis of certain significant
factors which have affected the Company's financial condition and results of
operations during the periods included in the accompanying statements of
operations.

General

For purposes of consistency in financial presentation, plant capacity factors
for Navy I, Navy II, and BLM (collectively the Coso Project), are based upon
a capacity amount of 80 net MW for each plant. Plant capacity factors for
Vulcan, Hoch (Del Ranch), Elmore, Leathers, (collectively the Partnership
Project) are based on contract nameplate amounts of 34, 38, 38, and 38 net MW
respectively, and for Salton Sea I, Salton Sea II and Salton Sea III plants
(collectively the Salton Sea Project), are based on contract nameplate
amounts of 10, 20 and 49.8 net MW, respectively (the Partnership Project and
the Salton Sea Project are collectively referred to as the Imperial Valley
Project). Each plant possesses an operating margin which periodically allows
for production in excess of the amount listed above. Utilization of this
operating margin is based upon a variety of factors and can be expected to
vary throughout the year under normal operating conditions.

The Coso Project and the Partnership Project sell all electricity generated
by the respective plants pursuant to seven long-term SO4 Agreements between
the projects and Southern California Edison Company ("Edison"). These SO4
Agreements provide for capacity payments, capacity bonus payments and energy
payments. Edison 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 and are significantly
higher in the months of June through September. Energy is sold at increasing
fixed rates for the first ten years of each contract and thereafter at
Edison's Avoided Cost of Energy.

The fixed price periods of the Coso Project 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. The Company's
share of the annual capacity payments is approximately $5,600 to $5,900 per
annum for each plant. The Company's share of bonus payments is approximately
$1,000 per annum for each plant.

The fixed price periods of the Partnership Project SO4 Agreements extend
until February 1996, December 1998, December 1998, and December 1999 for each
of the Vulcan, Hoch (Del Ranch), Elmore and Leathers Partnerships,
respectively. The Company's share of the annual capacity payments is
approximately  $12,000 and its share of the bonus payments is approximately
$2,200 in aggregate for the four plants.

The Company's SO4 Agreements provide for rates ranging from 11.4 cents per kWh
in 1995 to 15.6 cents per kWh in 1999.

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 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
Unit 1 was 4.99 cents per kWh during 1995. As the Salton Sea I PPA is not an SO4
Agreement, the energy payments do not revert to Edison's Avoided Cost of
Energy. The capacity payment is approximately $1,000 per annum.

The Salton Sea II and Salton Sea III Projects sell electricity to Edison
pursuant to 30-year modified SO4 Agreements. The contract capacities and
contract nameplates are 15 MW and 20 MW for Salton Sea II and 47.5 MW and
49.8 MW for Salton Sea III. 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 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 10.6 cents per kWh and 9.8 cents per kWh for Salton
Sea II and Salton Sea III, respectively. Thereafter, the monthly energy payments
will be Edison's Avoided Cost of Energy. For Salton Sea II only, Edison is
entitled to receive, at no cost, 5% of all energy delivered in excess of 80%
of contract capacity for the period April 1, 1994 through March 31, 2004. The
annual capacity payments for Salton Sea II and Salton Sea III are
approximately $2,000 and $8,300, respectively. The bonus payments for Salton
Sea II and Salton Sea III are approximately $500 and $1,400, respectively.

For the year ended December 31, 1995, Edison's average Avoided Cost of Energy
was 2.1 cents per kWh which is substantially below the contract energy prices
earned for the year ended December 31, 1995. Estimates of Edison's future
Avoided Cost of Energy vary substantially from year to year. The Company
cannot predict the likely level of Avoided Cost of Energy prices under the
SO4 Agreements and the modified SO4 Agreements at the expiration of the
scheduled payment periods. The revenues generated by each of the projects
operating under SO4 Agreements could decline significantly after the
expiration of the respective schedul ed payment periods.

Results of Operations

Three Years Ended December 31, 1995, 1994 and 1993 Sales of electricity and
steam increased to $335,630 in the year ended December 31, 1995 from $154,562
in the year ended December 31, 1994,  a 117.1% increase. This improvement was
primarily due to the addition of production from the Imperial Valley Project,
as a result of the acquisition of Magma in the first quarter of 1995, an
increase in the Coso Project's electricity revenues to $152,128 from $137,013
due to an increase in the Coso Project's electric kilowatt hour sales to
2,318.4 million kWh from 2,238.6 million kWh, and  an increased price per kWh
in accordance with the SO4 agreements and an increase in revenue received
from the Yuma Project which commenced operation in late May 1994.

The increase in sales of electricity and steam in 1994 to $154,562 from
$132,059 in 1993 was primarily due to a 2.4% increase in the Coso Project's
electric kWh sales to 2,238.6 million kWh from 2,186.7 million kWh, an
increased price per kWh in accordance with the SO4 agreements, and revenue
received from the Yuma Project, which commenced commercial operation in late
May, 1994. The increase in Coso Project kWh sales was primarily due to the
completion of new production wells.

The following operating data includes the aggregate capacity and electricity
production of the Coso Project:
<TABLE>
<CAPTION>
                                                1995                 1994                1993

<S>                                             <C>                  <C>                 <C>
Overall Capacity Factor                         110.3%               106.5%              104.0%
kWh Produced (in thousands)                     2,318,400            2,238,600           2,186,700
Capacity NMW (Average)                          240                  240                 240

</TABLE>
The Coso Plant capacity factor was 112.6% in the fourth quarter of 1995
compared to 112.2%, 106.1% and 110.2% for the third, second and first
quarters of 1995, respectively. A steam transfer agreement was signed and the
interties were constructed in the third quarter of 1995, providing for
increased production primarily at the BLM plant. Technical enhancements
provided for the increase in 1994 from 1993.

The following operating data includes the aggregate capacity and electricity
production of the Partnership Project:
<TABLE>
<CAPTION>
                                                1995                 1994                1993

<S>                                             <C>                  <C>                 <C>
Overall Capacity Factor                         105.9%               103.8%              100.7%
kWh Produced (in thousands)                     1,373,310            1,346,000           1,305,700
Capacity NMW (Average)                          148                  148                 148

</TABLE>
The Partnership Project capacity factor was 105.8% in the fourth quarter of
1995 compared to 108.0%, 107.5%, and 102.3% for the third, second, and first
quarters of 1995, respectively. The increased production in 1995 and 1994 are
a result of minimizing unscheduled downtime at the plants.

The following operating data includes the aggregate capacity and electricity
production of the Salton Sea Project:
<TABLE>
<CAPTION>
                                                1995                 1994                1993

<S>                                             <C>                  <C>                 <C>
Overall Capacity Factor                         86.5%                90.8%               91.3%
kWh Produced (in thousands)                     604,300              634,890             638,262
Capacity NMW (Average)                          79.8                 79.8                79.8

</TABLE>
The overall Salton Sea Project capacity factor was 86.8% in the fourth
quarter of 1995 compared to 93.9%, 78.3% and 86.8% for the third, second and
first quarters of 1995, respectively. The Salton Sea Project capacity factor
has decreased in 1995 from 1994 and 1993 due to the scheduled Salton Sea Unit
III overhaul in the second quarter of 1995 and the conversion of that unit to
the pH Mod technology in the fourth quarter of 1995.

Electric sale price per kWh for the Coso Project varies seasonally in
accordance with the rate schedule included in the SO4 agreements. The Coso
Project's average electricity prices per kWh in 1995, 1994 and 1993 were
comprised of (in cents):
<TABLE>
<CAPTION>
                                          Energy        Capacity & Bonus            Total

<C>                                        <C>                 <C>                  <C>
Average fiscal 1995                        11.81               1.82                 13.63
Average fiscal 1994                        10.91               1.90                 12.81
Average fiscal 1993                        10.11               1.93                 12.04

</TABLE>

Electric sale price per kWh for the Partnership Project also varies
seasonally in accordance with the rate schedule included in the SO4
agreements. The Partnership Project's average electricity prices per kWh in
1995, 1994 and 1993 were comprised of (in cents):
<TABLE>
<CAPTION>
                                          Energy        Capacity & Bonus            Total

<S>                                        <C>                 <C>                  <C>
Average fiscal 1995                        11.14               2.10                 13.24
Average fiscal 1994                        10.29               2.16                 12.45
Average fiscal 1993                         9.70               2.21                 11.91

</TABLE>

Electric sale price per kWh for the Salton Sea Project also varies seasonally
in accordance with the rate schedule included in the power purchase
agreements. The Salton Sea Project's average electricity prices per kWh in
1995, 1994 and 1993 were comprised of (in cents):
<TABLE>
<CAPTION>
                                          Energy        Capacity & Bonus            Total


<S>                                        <C>                 <C>                  <C>
Average fiscal 1995                         9.50               2.33                 11.83
Average fiscal 1994                        10.07               1.67                 11.74
Average fiscal 1993*                        9.54               2.59                 12.13

</TABLE>

*The 1993 data is for the nine months ended December 31, 1993

The Roosevelt Hot Springs steam field supplied 100% of customer power plant
steam requirements for each of the past three years. Steam sales from the
Roosevelt Hot Springs field were $2,206, $2,185, and $2,198 in 1995, 1994,
and 1993, respectively. The Desert Peak power plant operated at or near its
ten net megawatt capacity for each of the past three years. Electric sales
from Desert Peak were $5,115, $5,281 and $5,177 for the years 1995, 1994, and
1993, respectively. Beginning in 1996, the Desert Peak power plant will
receive payments for delivered electricity based on Sierra Pacific Power
Company's short-run Avoided Cost of Energy. The Yuma power plant availability
was effectively 100% during 1995 and delivered 89.2% of its 50 net MW plant
capacity. Electric and steam sales from Yuma were $16,975 in 1995 and $10,082
for approximately seven months in 1994.

Royalty income in 1995 of $19,482 is a result of the acquisition of Magma
which receives royalties from the Partnership Project, East Mesa Project and
the Mammoth Project.

Interest and other income increased in 1995 to $43,611 from $31,292 in 1994
and from $17,194 in 1993. The increase reflects management fee income
received from the Partnership Project partially offset by lower interest
income due to lower cash and investment balances.

The Company's cost per kWh was as follows (in cents):
<TABLE>
<CAPTION>
                                                                       1995           1994             1993

<S>                                                                  <C>              <C>              <C>
Plant operations (net of Company's
     management fees and Yuma fuel cost)                               2.31           1.82             1.98
General and administration                                              .78            .82             1.03
Royalties                                                               .81            .62              .65
Depreciation and amortization                                          2.41           1.34             1.39
Interest, less amounts capitalized                                     3.40           3.33             1.82


     Total                                                             9.71           7.93             6.87

</TABLE>
The Company's expenses as a percentage of sales of  electricity and steam
were as follows:
<TABLE>
<CAPTION>
                                                                     1995             1994             1993

<S>                                                                 <C>               <C>              <C>
Plant operations (net of Company's
     management fees and Yuma fuel cost)                             20.6 %           18.7 %           19.2 %
General and administration                                            7.0              8.4             10.0
Royalties                                                             7.2              6.4              6.3
Depreciation and amortization                                        21.5             13.7             13.5
Interest, less amounts capitalized                                   30.4             34.2             17.7


     Total                                                           86.7 %           81.4 %           66.7 %

</TABLE>

The Company's expenses increased in 1995 as a general result of the
acquisition of Magma, the greater electricity production of the Coso Project
and the inclusion of the costs from the Yuma plant for an entire year which
operated for only seven months in 1994.

The cost of plant operations increased to $79,294 in 1995 from $33,015 in
1994, an increase of 140.2%. The addition of the Imperial Valley Project
operations and the full year of operations of the Yuma Project (including
fuel purchases) resulted in the additional plant operations costs. Plant
operations costs for the plants the Company owned in 1994, excluding Yuma,
decreased $2,250 or 8.4% in 1995. The cost per kWh excluding Magma and Yuma
fuel costs decreased to 1.61 cents in 1995 from 1.82 cents and 1.98 cents in
1994 and 1993 respectively. The cost of plant operations increased to $33,015
in 1994 from $25,362 in 1993, an increase of 30.2% as a result of the cost of
plant operations at Yuma.

General and administration costs increased to $23,376 in 1995 from $13,012 in
1994, an increase of 79.6%. This increase is a result of the Company's
acquisition of Magma. General and administration costs per kWh for 1995,
1994, and 1993, continue to decrease due to a proportionally greater increase
in electrical production than general and administration costs. General and
administration costs decreased to $13,012 in 1994 compared to $13,158 in
1993, a 1.1% decrease.

Royalty cost increased to $24,308 in 1995 from $9,888 in 1994, a 145.8%
increase. The increase was due to the addition of the Imperial Valley
Project, increased revenue from the plants the Company owned in 1994 and
scheduled royalty increases associated with such plants. Overall, the royalty
cost per kWh was 0.81 cents in 1995 compared to 0.62 cents in 1994 and 0.65
cents in 1993. Royalty costs increased to $9,888 in 1994 from $8,274 in 1993,
an increase of 19.5% due to higher electrical sales and effective royalty
rate.

Depreciation and amortization increased to $72,249 in 1995 from $21,197 in
1994, a 240.8% increase. The increase was due to depreciation and
amortization from the Imperial Valley Project and amortization of excess of
cost over fair value of net assets acquired in connection with the purchase
of Magma. Depreciation and amortization for the plants the Company owned in
1994 increased to $25,935 in 1995 from $21,197 in 1994, a 22.4% increase.
Depreciation and amortization expense for 1995 was 2.41 cents per kWh
compared to 1.34 cents per kWh in 1994. The cost per kWh excluding Magma was
1.49 cents in 1995. Depreciation and amortization expense increased to
$21,197 in 1994 from $17,812 in 1993 a 19.0% increase. The increase in 1994
was due to the completion of H2S abatement systems and vacuum pumps at the
Coso plants and an increased number of wells.

Interest expense, less amounts capitalized, increased to $102,083 in 1995
from $52,906 in 1994, a 93.0% increase or 3.40 cents per kWh in 1995 
compared to 3.33 cents per kWh in 1994. The 1995 increase was primarily due
to the interest expense on the debt used to finance the acquisition of Magma,
the increase in the original issue discount amortization on the Senior
Discount Notes issued in March 1994 and interest expense on the convertible
debt, partially offset by the defeasance of the Senior Notes in March 1994.
Net interest expense in 1994 increased due primarily to the Company's
issuance of Senior Discount Notes in March of 1994. Net interest increased to
$52,906 in 1994 from $23,389 in 1993, an increase of 126.2%, or 3.33 cents
per kWh in 1994, compared to 1.82 cents per kWh in 1993.

The provision for income taxes increased to $30,631 in 1995 from $17,002 in
1994, and decreased to $17,002 in 1994 from $18,184 in 1993. The effective
tax rate was 31.6%, 30.5% and 29.7% in 1995, 1994, and 1993, respectively.

Income before the provision for income taxes increased to $97,051 in 1995
from $55,836 in 1994, a 73.8% increase. Net income available to common
shareholders increased to $62,335 or $1.25 per common share for the year
ended December 31, 1995 compared to $31,817 or $.89 per common share in 1994
and $42,544 or $1.11 per common share in 1993. Net income for the year ended
December 31, 1994 was reduced by $2,007 or $.06 per share due to an
extraordinary item. Net income for the year ended December 31, 1993 was
increased by $4,100 or $.11 per share due to a cumulative effect of a change
in accounting principle.

Earnings per share in 1995, 1994, and 1993 were favorably impacted by the
Company's stock repurchase plan.

Liquidity and Capital Resources

Cash and short-term investments were $106,304 at December 31, 1995 as
compared to $304,004 at December 31, 1994. In addition, the Coso Project and
Partnership Project retained cash and investments in project control accounts
of which the Company's share was $77,590 and $54,087 at December 31, 1995 and
1994, respectively. Distributions out of the project control accounts are
made monthly to the Company for operation and maintenance and capital costs
and semiannually to each Coso Project partner and Partnership Project partner
for profit sharing under a prescribed calculation subject to mutual agreement
by the partners. In addition to these liquid instruments, the Company
recorded separately restricted cash of $149,227 and $131,775 at December 31,
1995 and 1994, respectively. The restricted cash balances are comprised
primarily of amounts deposited in restricted accounts from which the Company
will provide its equity contribution requirements relating to the Salton Sea
Unit IV, Upper Mahiao, Mahanagdong, and Malitbog projects and the Company's
proportionate share of Coso Project and Partnership Project cash reserves for
the debt service reserve funds.

Accounts receivable normally represents two months of revenues, and
fluctuates with both production and price per kWh.

The balance due from/to the Joint Ventures relates to operations,
maintenance, and management fees for managing the Coso Project and the
Partnership Project as well as advances and deferred revenue on the
international projects. This amount fluctuates based on the timing of
billings and incurrence of costs.

The Company repurchased 102 common shares during 1995 for  the aggregate
amount of $1,590. The Company repurchased 3,765 shares of common stock in
1994 at an aggregate amount of $65,119. As of December 31, 1995 the Company
holds 87 shares of treasury stock at a cost of $1,348 to provide shares for
issuance under the Company's employee stock option and share purchase plan
and other outstanding convertible securities. The repurchase plan attempts to
minimize the dilutive effect of the additional shares issued under these
plans.

The Company has acquired all of the outstanding equity interest in Magma
Power Company ("Magma") in a two-step transaction accounted for as a purchase
according to the terms of a merger agreement whereby on January 10, 1995, the
Company acquired approximately 51% of the outstanding shares of Magma common
stock (the "Magma Common Stock") through a cash tender offer (the "Magma
Tender Offer") and on February 24, 1995 the Company acquired the remaining
49% of Magma Common Stock not owned by the Company through a merger (the
"Merger"). Each outstanding share of Magma Common Stock (other than shares of
Magma Common Stock held by the Company, CE Acquisition Company, Inc., a
wholly owned subsidiary of the Company, or any other direct or indirect
subsidiary of the Company and shares of Magma Common Stock held in the
treasury of Magma) was converted into the right to receive an average of
approximately $38.75 per share of Magma Common Stock. The Company paid the
Merger consideration solely in cash, funded with the net proceeds of a public
common stock offering of 15,170 shares (the "Offering") and the proceeds of
a direct sale of 1,500 shares to Peter Kiewit Sons', Inc. (the "Direct Sale")
at $17.00 per share which together netted $275,653, over-allotment proceeds
of $24,735 on the sale of 1,500 shares, borrowings of $500,000 under bank
credit facilities ("Merger Facilities"), and general corporate funds of the
Company. Magma is engaged in independent geothermal power operations similar
to those of the Company.

In July 1995 the Company recapitalized Magma and the related Merger
Facilities with proceeds received through the issuance of notes and bonds as
described below.

On July 21, 1995 the Company issued $200,000 of 9 7/8% Limited Recourse
Senior Secured Notes Due 2003 (the "Notes"). The Notes are secured by an
assignment and pledge of 100% of the outstanding capital stock of Magma. On
or prior to June 30, 1998, the Company may, at its option, redeem up to an
aggregate of 35% of the principal amount of the Notes originally issued at a
redemption price equal to 109.875% of the principal amount thereof plus
accrued interest to the redemption date. The Notes are redeemable at the
option of the Company, in whole or in part, at the redemption prices of
104.9375%, 102.46875% and 100%, on or after June 30, 2000, 2001 and 2002,
respectively, plus accrued interest to the date of redemption.
Concurrent with the issuance of the Notes, the Company through its wholly
owned subsidiary, Salton Sea Funding Corporation ("Funding Corporation"),
completed a sale to institutional buyers of $475,000 principal amount of
Salton Sea Notes and Bonds, which are nonrecourse to the Company. The Funding
Corporation debt securities were offered in three tranches as follows:

$232,750 6.69% Senior Secured Series A Notes
         Due May 30, 2000
$133,000 7.37% Senior Secured Series B Bonds
         Due May 30, 2005
$109,250 7.84% Senior Secured Series C Bonds
         Due May 30, 2010

The net proceeds of the Notes and the Salton Sea Notes and Bonds were used to
(a) recapitalize Magma and the related Merger Facilities (b) refinance
approximately $102,000 of existing indebtedness of the Salton Sea Project,
and (c) finance the Salton Sea Unit IV in the amount of $115,000. Pursuant to
the Depositary Agreement, Funding Corporation established a debt service
reserve fund in the form of a letter of credit in the initial amount of
$50,000 from which scheduled interest and principal payments can be made.

The Company is actively seeking to develop, construct, own and operate new
power and infrastructure projects utilizing geothermal and other
technologies, both domestically and internationally, the completion of any of
which is subject to substantial risk. Development can require the Company to
expend significant sums for preliminary engineering, field development,
permitting, legal and other financing related costs. The Company's future
growth is dependent, in large part, upon the demand for significant amounts
of additional electrical generating capacity and the Company's ability to
obtain contracts to supply portions of this capacity. There can be no
assurance that development, financing or construction efforts on any
particular project, or the Company's efforts generally, will be successful.

The Company believes that the international independent power market holds
the majority of new opportunities for financially attractive private power
development in the next several years. The financing, construction and
development of projects outside the United States entail significant
political and financial risks (including, without limitation, uncertainties
associated with first time privatization efforts in the countries involved,
currency exchange rate fluctuations, currency repatriation restrictions,
political instability, civil unrest and expropriation) and other structuring
issues that have the potential to cause substantial delays or material
impairment of value to the project being developed, which the Company may not
be fully capable of insuring against. The uncertainty of the legal
environment in certain foreign countries in which the Company may develop or
acquire projects could make it more difficult for the Company to enforce its
rights under agreements relating to such projects. In addition, the laws and
regulations of certain countries may limit the ability of the Company to hold
a majority interest in some of the projects that it may develop or acquire.
The Company's international projects may, in certain cases, be terminated by
a government.

In 1995, the Company has commenced development of and has obtained financing
for the Casecnan Project, a multipurpose irrigation and hydroelectric power
facility with a rated capacity of approximately 150 net MW located on the
island of Luzon in the Philippines. The total project cost for the facility
is approximately $495,000. The current capital structure consists of term
loans of $371,500 and $123,836 in equity contributions. The Company's portion
of the contributed equity is $61,918.

The project is structured as a 20 year BOOT, in which the Company's indirect 
subsidiary CE Casecnan Water and Energy Company, Inc., a Philippine
corporation, will be responsible as the BOOT operator. The fixed price, date-
certain turnkey contractors consist of Hanbo Corporation and You One
Engineering & Construction Co., Ltd. of South Korea.

Additionally in 1995, the Company has commenced construction of an additional
40 net MW electric generating facility (the "Salton Sea Unit IV") in the
Imperial Valley pursuant to an amended and restated 30-year power purchase
agreement with Edison. The Salton Sea Unit IV has a target completion date of
July 1996 and an estimated capital construction cost of $135,000. As of
December 31, 1995, the Company has invested $64,935 in the Salton Sea Unit
IV.

In April 1994, the Company closed the financing for the 119 net MW Upper
Mahiao geothermal power project located in the Philippines. The total project 
cost for the facility is approximately $218,000. The Company will supply
approximately $56,000 of equity and project debt financing will constitute
the balance of approximately $162,000. A syndicate of international
commercial banks is providing the construction financing. The Export-Import
Bank of the U.S. ("Ex-Im Bank") is providing political risk insurance to the
commercial banks on the construction loan and will provide the preponderance
of project term financing upon satisfaction of conditions associated with
commercial operation. As of December 31, 1995, draws on the construction loan
totalled $134,619, and the Company has invested $51,137. The Overseas Private
Investment Corporation ("OPIC") is providing political risk insurance on the
equity investment by the Company in this project. The Upper Mahiao project
commenced construction in April of 1994, and is expected to be in service in
July of 1996. The project is structured as a ten year Build-Own-Operate-
Transfer ("BOOT"), in which the Company's subsidiary CE Cebu Geothermal Power
Company, Inc., the project company, will be responsible for implementing
construction of the geothermal power plant and, as owner, for providing
operations and maintenance during the ten year BOOT period. The electricity
generated by the Upper Mahiao geothermal power plant will be sold to the
Philippine National Oil Company-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. Ormat Inc. of Sparks, Nevada is the
turnkey contractor for the project.

PNOC-EDC will be 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 Energy Conversion Agreement
("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.
The convertibility of Philippine peso receipts into U.S. dollars is insured
by OPIC. 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.

In August 1994, the Company closed the financing for the 165 net MW
Mahanagdong project located in the Philippines. The total project cost for
the facility is approximately $320 million. The capital structure consists of
a term loan of $240 million and approximately $80 million in equity
contributions. OPIC and a consortium of commercial lenders led by Bank of
America NT&SA is providing the construction debt financing facility. The debt
provided by the commercial lenders is insured against political risk by the
Ex-Im Bank. Ten-year term debt financing (which will replace the construction
debt) will be provided by Ex-Im Bank and by OPIC. The Mahanagdong project has
commenced construction and as of December 31, 1995, the Company's
proportionate share of draws on the construction loan totalled $39,716 and
equity investments made by a subsidiary of the Company totalled $29,604. OPIC
is providing political risk insurance on the equity. The Mahanagdong project
has begun construction and is targeted for service in July, 1997. As with the
Upper Mahiao project, the Mahanagdong project is structured as a ten-year
BOOT, 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. After a ten year cooperation
period, and the recovery by the Company of its capital investment plus
incremental return, the plant will be transferred to PNOC-EDC at no cost. The
Mahanagdong project will be built, owned and operated by CE Luzon Geothermal
Power Company, Inc., a Philippine corporation, that is expected to be owned
post-completion as follows: 45% by the Company, 45% by Kiewit, and up to 10%
by another industrial company. The turnkey contractor consortium consists of
Kiewit Construction Group, Inc. (with an 80% interest) and CE Holt Co., a
wholly owned subsidiary of the Company (with a 20% interest).

The electricity generated by the Mahanagdong project will be sold to PNOC-
EDC, on a "take or pay" basis, which is also responsible for supplying the
facility with the geothermal steam. The terms of the Mahanagdong ECA are
substantially similar to those of the Upper Mahiao ECA. All of PNOC-EDC's
obligations under the Mahanagdong ECA are supported by the Government of the
Philippines through a performance undertaking. The Capacity Fees are expected
to be approximately 97% of total revenues at the design capacity levels and
the Energy Fees are expected to be approximately 3% of such total revenues.

In December 1994, financing was closed and construction commenced on the
Malitbog Project, a 216 net MW geothermal project, which will be located on
the island of Leyte. The Malitbog Project will be built, owned and operated
by  Visayas Geothermal Power Company ("VGPC"), a Philippine general
partnership that is wholly owned, indirectly, by the Company. VGPC will sell
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
NAPOCOR.

The Malitbog Project has a total project cost of approximately $280 million,
including interest during construction and project contingency costs. Credit
Suisse and OPIC have provided a total of $210 million of construction and
term loan facilities, the $135 million international commercial bank portion
of which is supported by political risk insurance from OPIC. As of December
31, 1995, draws on the construction loan totalled $36,863, the equity
investments made by subsidiaries of the Company totalled $70,000 and advances
by subsidiaries of the Company totalled $2,820. The advances will be repaid
by draws on the construction loan. The Company's equity contribution to VGPC
of $70,000 is covered by political risk insurance from OPIC and the
Multilateral Investment Guarantee Agency ("MIGA"). As with the Upper Mahiao
project, the Malitbog project is structured as a BOOT, 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. After a ten year cooperation period, and the recovery by
the Company of its capital investment plus incremental return, the plant will
be transferred to PNOC-EDC at no cost.

The Malitbog Project is being constructed by Sumitomo Corporation pursuant to
a fixed-price, date-certain, turnkey supply and construction contract.
Construction of the facility has begun, with commercial operation of Unit 1
scheduled to commence in July 1996 and commercial operation of Unit 2 and
Unit 3 scheduled to commence in July 1997.

Magma is seeking new long-term final SO4 power purchase agreements in
southern California through the bidding process adopted by the CPUC under its
1992 Biennial Resource Plan Update ("BRPU"). In its 1992 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 (collectively, the "IOUs"). 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 (69 net MW) and SDG&E (94 net MW), with in-service dates in
1997 and 1998. However, the IOUs have to date challenged and may continue to
challenge the order and there can be no assurance that power sales contracts
will be executed or that any such projects will be completed.

In light of the regulatory uncertainty concerning the BRPU awards resulting
from such IOU challenges, in March 1995 Magma entered into a settlement
agreement with Edison relating to the 69 net MW of capacity awarded to Magma
as a winning bidder in the BRPU solicitation. The agreement (which is subject
to CPUC approval) provides for three lump sum termination payments in lieu of
signing a power sales contract with Edison for the 69 net MW of BRPU
capacity. The amount of the  termination payments is subject to a
confidentiality agreement but provides Edison's ratepayers with very
significant savings when compared to payments that would otherwise be made to
Magma over the life of the proposed BRPU power sales contract.

The agreement also provides Edison with an option, which can be exercised
until February 1, 2002, to negotiate a power sales contract for 69 net MW of
geothermal capacity and energy on commercially reasonable prices and terms,
without giving effect to termination payments previously paid.

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

CONSOLIDATED BALANCE SHEETS
as of December 31, 1995 and December 31, 1994
dollars and shares in thousands, except per share amounts

<TABLE>
<CAPTION>

ASSETS                                                                                 1995               1994  

<S>                                                                              <C>                   <C>
Cash and investments                                                             $    72,114           $254,004 
Joint venture cash and investments (Note 9)                                           77,590             54,087 
Restricted cash (Notes 3, 7, 9 and 10)                                               149,227            131,775 
Short-term investments                                                                34,190             50,000 
Accounts receivable                                                                   57,909             28,272 
Due from Joint Ventures                                                               27,273                --- 
Properties, plants, contracts and equipment,
 net (Notes 5, 7, 9 and 10)                                                        1,778,589            561,643 
Notes receivable - Joint Ventures (Note 19)                                           14,254             12,627 
Excess of cost over fair value of net assets
   acquired, net (Note 3)                                                            302,288                --- 
Equity investment in Casecnan (Note 8)                                                60,815                --- 
Deferred charges and other assets                                                     79,789             38,737 


   Total assets                                                                   $2,654,038         $1,131,145 


LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable                                                                   $   6,638           $  1,679 
Other accrued liabilities                                                             87,892             42,658 
Project finance loans (Note 9)                                                       257,933            233,080 
Construction loans (Note 10)                                                         211,198             31,503 
Senior discount notes (Note 11)                                                      477,355            431,946 
Salton Sea notes and bonds (Note 5)                                                  452,088                --- 
Limited recourse senior securednotes (Note 5)                                        200,000                --- 
Convertible subordinated debentures (Note 12)                                        100,000            100,000 
Convertible debt (Note 13)                                                            64,850                --- 
Deferred income taxes (Note 14)                                                      226,520             26,568 
Due to Joint Venture                                                                     ---                269 


   Total liabilities                                                               2,084,474            867,703 


Deferred income (Note 7)                                                              26,032             19,851 


Commitments and contingencies (Notes 6 and 18)
Redeemable preferred stock (Note 13)                                                     ---             63,600 


Stockholders' equity (Notes 13, 15, 16, and 17):
Preferred stock - authorized 2,000 shares, 
   no par value (Note 15)                                                                ---                --- 
Common stock - par value $0.0675 per share,
   authorized 80,000 and 60,000 shares, issued
   50,680 and 35,649 shares, outstanding 50,593
   and 31,849 shares                                                                   3,421              2,407 
Additional paid in capital                                                           343,406            100,421 
Retained earnings                                                                    205,059            142,937 
Treasury stock - 87 and 3,800 common shares at cost                                   (1,348)           (65,774)
Unearned compensation - restricted stock (Note 16)                                    (7,006)               --- 


   Total stockholders' equity                                                        543,532            179,991 


   Total liabilities and stockholders' equity                                     $2,654,038          $1,131,145

</TABLE>

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

CONSOLIDATED STATEMENTS OF OPERATIONS
for the three years ended December 31, 1995
dollars and shares in thousands, except per share amounts

<TABLE>
<CAPTION>
                                                                          1995               1994        1993   

<S>                                                                    <C>                <C>           <C> 
Revenue:
Sales of electricity and steam                                          $335,630           $154,562      $132,059 
Royalty income                                                            19,482                ---           --- 
Interest and other income                                                 43,611             31,292        17,194 


   Total revenues                                                        398,723             185,854      149,253 


Cost and expenses:
Plant operations                                                          79,294             33,015         25,362 
General and administration                                                23,376             13,012         13,158 
Royalties                                                                 24,308              9,888          8,274 
Depreciation and amortization                                             72,249             21,197         17,812 
Loss on equity investment in Casecnan                                        362                ---            ---
Interest                                                                 134,637             62,837          30,205 
Less interest capitalized                                                (32,554)            (9,931)         (6,816)


   Total expenses                                                        301,672            130,018          87,995 


Income before provision for income taxes                                  97,051             55,836          61,258 
Provision for income taxes (Note 14)                                      30,631             17,002          18,184 
 

Income before change in accounting principal 
  and extraordinary item                                                  66,420             38,834          43,074
Cumulative effect of change in accounting
  principal (Note 14)                                                        ---                ---           4,100 
Extraordinary item (Note 20)                                                 ---             (2,007)            ---  


Income before minority interest and
   preferred dividends                                                    66,420             36,827          47,174 
Minority interest                                                          3,005                ---              --- 


Net Income                                                                63,415             36,827          47,174 
Preferred dividends                                                        1,080              5,010           4,630 


Net income available to common stockholders                              $62,335            $31,817         $42,544 


Income per share before change in accounting
  principal and extraordinary item                                         $1.25               $.95          $ 1.00 


Cumulative effect of change in accounting
  principal (Note 14)                                                       ---                 ---             .11 


Extraordinary item (Note 20)                                                ---                (.06)            ---  


Net income per share - primary                                             $1.25              $ .89          $ 1.11 


Net income per share - fully diluted                                       $1.18              $ .88           $1.09 


Average number of shares outstanding - primary                            49,971             35,721          38,485 


Fully diluted shares                                                      57,742             40,166          40,781 


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

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
for the three years ended December 31, 1995
dollars and shares in thousands


</TABLE>
<TABLE>
<CAPTION>

                                             Outstanding               Additional
                                             Common         Common     Paid-In      Retained   Treasury     Unearned  
                                             Shares         Stock      Capital      Earnings    Stock     Compensation  Total

<S>                                           <C>         <C>         <C>          <C>         <C>        <C>           <C>
Balance December 31, 1992                     35,258      $ 2,380     $ 97,977     $ 68,407    $   ---    $    ---      $168,764 
Exercise of stock options                        258           18          937          ---        ---         ---           955 
Issuance of stock for purchase of 
   The Ben Holt Co.                               87            6        1,551        ---          ---         ---         1,557 
Purchase of treasury stock                      (157)         ---          ---        ---       (2,897)        ---        (2,897)
Preferred stock dividends, Series C,
   including cash distributions of $100          ---          ---          ---       (4,550)       ---         ---        (4,550)
Tax benefit from stock plan                      ---          ---          500          ---        ---         ---           500 
Net income before preferred dividends            ---          ---          ---       47,174        ---         ---        47,174 



Balance December 31, 1993                     35,446        2,404      100,965      111,031       (2,897)      ---       211,503 
Exercise of stock options                         46            3          379          ---          ---       ---           382 
Purchase of treasury stock                    (3,765)         ---          ---          ---      (65,119)      ---       (65,119)
Exercise of stock options from
   treasury stock                                 96          ---       (1,473)         ---        1,772       ---           299 
Employee stock purchase plan issues
   from treasury stock                            26          ---         (122)         ---          470       ---           348 
Preferred stock dividends, Series C,
   including cash distribution of $121           ---          ---          ---       (4,921)         ---       ---        (4,921)
Tax benefit from stock plan                      ---          ---          672          ---          ---       ---           672 
Net income before preferred dividends            ---          ---          ---       36,827          ---       ---        36,827 
 

Balance December 31, 1994                     31,849        2,407      100,421      142,937      (65,774)      ---       179,991 
Equity offering                               18,170        1,004      240,825       56,801          ---       ---       298,630 
Exercise of stock options                        102            7          303          ---          ---       ---           310 
Restricted stock                                 500          ---          848          ---        8,652    (9,500)          --- 
Amortization of unearned compensation            ---          ---          ---          ---          ---     2,494         2,494 
Employee stock purchase plan issues               41            3          559          ---          ---       ---           562 
Exercise of stock options from
   treasury stock                                 33          ---         (416)         ---          563       ---           147 
Purchase of treasury stock                      (102)         ---          ---          ---       (1,590)      ---        (1,590)
Preferred stock dividends, Series C,
   including cash distribution of $43            ---          ---          ---       (1,293)         ---       ---        (1,293)
Tax benefit from stock plan                      ---          ---          866          ---          ---       ---           866 
Net income before preferred dividends            ---          ---          ---       63,415          ---       ---        63,415 
 

Balance December 31, 1995                     50,593      $ 3,421     $343,406     $205,059      $(1,348)  $(7,006)     $543,532 

</TABLE>

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
for the three years ended December 31, 1995
dollars in thousands
<TABLE>
<CAPTION>
                                                                             1995           1994          1993

<S>                                                                          <C>            <C>           <C> 
Cash flows from operating activities:
Net incom                                                                    $ 63,415       $ 36,827      $ 47,174 
Adjustments to reconcile net cash flow from operating activities:
     Depreciation and amortization                                              5,244         21,197        17,812 
     Amortization of excess of cost over fair value
       of net assets acquired                                                   7,005            ---           --- 
     Amortization of original issue discount                                   45,409         31,946           --- 
     Amortization of deferred financing costs                                   8,979          1,687         1,013 
     Amortization of unearned compensation                                      2,494            ---           --- 
     Provision for deferred income taxes                                       13,983          8,258         3,098 
     Loss on equity investment in Casecnan                                        362            ---           --- 
     Expense of previously deferred financing costs                               ---            198           --- 
     Changes in other items:
       Accounts receivable                                                        213         (6,614)       (5,486)
       Accounts payable and other accrued liabilities                           3,838         23,864          (784)
       Deferred income                                                          6,181           (437)         (876)
       Income tax payable                                                       2,084         (4,500)        4,000 
       Other assets                                                               ---             ---         (177)


     Net cash flows from operating activities                                 219,207        112,426        65,774 


Cash flows from investing activities:
Capital expenditures relating to power plants
  and development of existing projects                                        (25,884)       (37,717)      (26,860)
Acquisition of equipment                                                       (1,236)          (361)       (1,104)
Purchase of Magma, net of cash acquired                                      (907,614)        (3,043)          --- 
Upper Mahiao - construction in progress                                      (140,350)       (48,554)          --- 
Mahanagdong - construction in progress                                        (55,117)       (21,443)          --- 
Malitbog - construction in progress                                           (94,188)           ---           --- 
Investment in Casecnan                                                        (61,177)           ---           --- 
Other international development                                                (8,973)        (2,445)          --- 
Salton Sea Expansion                                                          (62,430)           ---           --- 
Pacific Northwest, Nevada, and Utah exploration costs                         (10,445)        (8,493)      (19,060)
Decrease (increase) in short-term investment                                   80,565        (50,000)          --- 
Decrease (increase) in restricted cash                                        (17,452)       (83,670)       14,409 
Decrease (increase) in other investments and assets                            14,519          1,847           941 
Yuma-construction in progress                                                     ---            ---       (40,167)
Tansmission line deposit                                                          ---            ---         7,684 


     Net cash flows from investing activities                              (1,289,782)      (253,879)      (64,157)


Cash flows from financing activities:
Proceeds from sale of common and treasury stock
     and exercise of stock options                                            299,649          1,580         2,912 
Proceeds from Salton Sea notes and bonds                                      475,000            ---           --- 
Proceeds from limited recourse senior secured notes                           200,000            ---           --- 
Proceeds from merger facility                                                 500,000            ---           --- 
Recapitalization of merger facility                                          (500,000)           ---           --- 
Repayment of project loans                                                   (153,752)       (13,800)      (16,724)
Construction loans                                                            179,695         31,503           --- 
Repayment of Salton Sea notes and bonds                                       (22,912)           ---           --- 
Deferred charges relating to debt financing                                   (34,733)       (11,905)       (2,582)
Decrease (increase) in amounts due from Joint Ventures                        (29,169)           316        (3,146)
Purchase of treasury stock                                                     (1,590)       (65,119)       (2,897)
Proceeds from issue of Senior Discount Note                                       ---        400,000           --- 
Proceeds from issue of convertible subordinated debentures                        ---            ---       100,000 
Defeasance of senior notes                                                        ---        (35,730)          --- 

     Net cash flows from financing activities                                 912,188        306,845        77,563 

Net increase (decrease) in cash and investments                              (158,387)       165,392        79,180 

Cash and investments at beginning of period                                   308,091        142,699        63,519 

Cash and investments at end of period                                        $149,704       $308,091      $142,699 

Interest paid (net of amounts capitalized)                                   $ 50,840       $ 12,624       $20,136 

Income taxes paid                                                            $ 14,812       $  4,926        $6,819 

</TABLE>

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

NOTES to Consolidated Financial Statements
For the Three Years Ended December 31, 1995
Dollars and Shares in Thousands, Except Per Share Amounts

1.     Business

CalEnergy Company, Inc. (the "Company"), formerly California Energy Company,
Inc., was formed in 1971. It is primarily engaged in the development of
geothermal resources and conversion of such resources into electrical power
and steam for sale to electric utilities, and the development and operation
of other environmentally responsible forms of power generation.

The Company has organized several partnerships and joint ventures (herein
referred to as Coso Joint Ventures) in order to develop geothermal energy at
the China Lake Naval Air Weapons Station, Coso Hot Springs, China Lake,
California. Collectively, the projects undertaken by these Coso Joint
Ventures are referred to as the Coso Project. The Company is the operator and
holds interests between 46.4% and 50% in the Coso Joint Ventures after
payout. Payout is achieved when a Coso Joint Venture has returned the initial
capital to the Coso Joint Venturers. In addition, the Company is developing
geothermal resources in Northern California and Oregon (collectively the
Pacific Northwest). In January 1991, the Company acquired a power plant and
an interest in steam fields in Nevada and Utah (See Note 7). In 1992, the
Company entered into the natural gas-fired electrical generation market
through the purchase of a development opportunity in Yuma, Arizona.
Commercial operation of the Yuma project commenced in late May 1994. In 1993,
the Company started developing a number of international power project
opportunities where private power generating programs have been initiated,
including the Philippines and Indonesia. In addition, in January 1995, the
Company acquired approximately 51% of Magma Power Company ("Magma") and
completed the acquisition in February 1995 by acquiring the remaining
percentage of approximately 49% of Magma Common Stock. Magma's operating
assets include four projects referred to as the Partnership Project of which
Magma has a 50% interest, the Salton Sea Project of which Magma owns 100% and
certain royalties received from the Partnership Project and other non related
projects (See Note 3).

2.     Summary of Significant Accounting Policies

The consolidated financial statements include the accounts of the Company,
its wholly-owned subsidiaries, and its proportionate share of the joint
ventures in which it has invested. All significant inter-enterprise
transactions and accounts have been  eliminated.

Investments and Restricted Cash

Investments other than restricted cash are primarily commercial paper and
money market securities. The restricted cash balance includes such securities
and mortgage backed securities, and is mainly composed of amounts deposited
in restricted accounts from which the Company will source its equity
contribution requirements relating to the Upper Mahiao, Mahanagdong,
Malitbog, Salton Sea Unit IV projects and of the Coso Joint Ventures' and
Partnership Project's debt service reserve funds. The debt service reserve
funds are legally restricted to their use and require the maintenance of
specific minimum balances.

Effective January 1, 1994, the Company adopted the provisions of Statement of
Financial Accounting Standards No. 115 ("SFAS 115") "Accounting for Certain
Investments in Debt and Equity Securities." Adoption of SFAS 115 had no
material effect on the Company's individual or combined financial position or
results of operations. In accordance with the provisions of SFAS 115, the
Company classifies its investments, and accounts for changes in fair value,
as follows:

-      Debt securities that the Company has the positive intent and ability to
       hold to maturity are classified as held-to-maturity securities and
       reported at amortized cost.

-      Debt and equity securities that are bought and held principally for the
       purpose of selling them in the near term are classified as trading
       securities and reported at fair value, with unrealized gains and losses
       included in earnings.

-      Debt and equity securities not classified as either held-to-maturity
       securities or trading securities are classified as available-for-sale
       securities and reported at fair value, with unrealized gains and losses
       excluded from earnings and reported as a separate component of
       stockholders' equity.

At December 31, 1995, all of the Company's investments are classified as
held-to-maturity and are accounted for at their amortized cost basis. The
carrying amount of the investments approximates the fair value based on
quoted market prices as provided by the financial institution which holds the
investments.

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 characteristics of the
underlying resource; exploration costs and development costs, other than
production wells, are generally amortized over the weighted average remaining
term of the Company's power and steam purchase contracts. For purposes of
current period visibility and disclosure, all such costs are identified in
the Consolidated Statements of Cash Flows as they are incurred.

Deferred Well and Rework Costs

Well rework costs are deferred and amortized over the estimated period
between reworks. These deferred costs of $7,086 and $733 at  December 31,
1995 and 1994, respectively, 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,
resulting in a composite rate of depreciation of approximately 2.67% per
annum. 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 principles 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.

Process licenses and related technologies are amortized using the straight-
line method over the estimated useful life of the license.

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. Loan fees are amortized using the implicit interest method; other
deferred financing costs are amortized using the straight-line method.

Revenue Recognition

Revenues are recorded based upon service rendered and electricity and steam
delivered to the end of the month. See Note 7 for contractual terms of power
sales agreements. Royalties contractually payable to the Company by the
Partnership Project are recorded on an accrual basis, net of the Company's
50% share of the corresponding partnership project expense. Royalties earned
from providing geothermal resources to power plants operated by other
geothermal power producers are recorded on an accrual basis.

Deferred Income Taxes

On January 1, 1993, the Company adopted Statement of Financial Accounting
Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes." The adoption
of SFAS 109 changes the Company's method of accounting for income taxes from
the deferred method as required by Accounting Principles Board Opinion  No.
11 to an asset and liability approach.

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. Although management uses its best judgement in
estimating the fair value of these financial instruments, there are inherent
limitations in any estimation technique. Therefore, the fair value estimates
presented herein are not necessarily indicative of the amounts which the
Company could realize in a current transaction.

The Company assumes that the carrying amount of short-term financial
instruments approximates their fair value. For these purposes, short-term is
defined as any item that matures, reprices, or represents a cash transaction
between willing parties within six months or less of the measurement date.

Net Income per Common Share

Primary and fully diluted earnings per common share are based on the weighted
average number of common and dilutive common equivalent shares outstanding
during the period computed using the treasury stock method. Fully diluted
earnings per share also assumes the conversion of the Convertible
Subordinated Debentures into 4,444 common shares at a conversion price of
$22.50 per share (even though the common share price was $19.50 at December
31, 1995) and the exercise of all dilutive stock options outstanding at their
option prices, with the option exercise proceeds used to repurchase shares of
common stock at the ending market price for fully diluted earnings per share.
For primary earnings per share, shares of common stock are assumed to be
repurchased at the average price for the period.

Cash Flows

The statement of cash flows classifies changes in cash according to
operating, investing, or financing activities. Investing activities include
capital expenditures incurred in connection with the power plants, wells,
resource development, and exploration costs. The Company considers all
investment instruments purchased with a maturity of three months or less to
be cash equivalents. Restricted cash is not considered a cash equivalent.

Reclassification

Certain amounts in the fiscal 1994 and 1993 financial statements and
supporting footnote disclosures have been reclassified to conform to the
fiscal 1995 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.     Purchase of Magma Power Company

On January 10, 1995, the Company acquired approximately 51% of the
outstanding shares of common stock of Magma Power Company (the "Magma Common
Stock") through a cash tender offer (the "Magma Tender Offer") and completed
the Magma acquisition on February 24, 1995 by acquiring the approximately 49%
of the outstanding shares of Magma Common Stock not owned by the Company
through a merger. Magma is engaged in independent power operations similar to
those of the Company. The results of operations of the Company include the
results of operations of Magma from January 10, 1995, to December 31, 1995
adjusted for the Company's percentage ownership during that time period.

The Magma acquisition has been accounted for as a purchase business
combination pursuant to the principles 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. 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 fair value of operating facilities, net of salvage value, and exploration
and development cost is depreciated using the straight-line method over the
remaining portion (approximately 24 years) of the original 30 year life.

Power sales agreements have been assigned values separately for each of (1)
the remaining portion (1 to 5 years) of the scheduled price periods of the
power sales agreements; (2) the 20 year avoided cost periods of the power
sales agreements, and are being amortized separately over such periods using
the straight line method; and (3) the 163 net MW BRPU Award for which the
related plants will either be constructed or the contract rights will be
bought out; amortization of such values has been deferred until the plants
have been constructed and production commences or the buyout proceeds have
been applied against such values.

The Salton Sea reservoir contains commercial quantities of extractable
minerals. The fair value has been allocated to mineral reserves which was
based on the estimated net cash flows generated from producing such minerals.
The fair value assigned to the mineral reserves will be amortized on the
units of production method upon commencement of commercial production.

Fair value has been assigned to contracts for which the plants are presently
under construction and energy production is not expected to commence before
1996. Accordingly, revenues, period operating costs, depreciation of the
remaining capital costs to be incurred for the completion of such facilities
and amortization of this acquisition cost are not presently included in the
Company's statements of  operations.

A process license was allocated fair value which represents the economic
benefits expected to be realized from the installation of the license and
related technology at the Imperial Valley. The fair value assigned to the
process license is being amortized using the straight-line method over the
remaining estimated useful life of the license. Deferred finance costs are
being amortized using the level yield method over the term of the related
debt.

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

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
the Company on a nonrecourse basis, secured by the Magma stock acquired, and
the Company lent the proceeds of such loans to Magma in exchange for a
secured term note from Magma (the "Tender Note"). The loans under the Tender
Facility were repaid from funds received from the Merger Facilities,
described below.

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 (see Note 4) and general corporate funds of the Company, were used
to complete the Magma acquisition.

In July 1995, the Company recapitalized Magma and the related Merger
Facilities from proceeds received through the issuance of notes and bonds as
described in Note 5.

Unaudited proforma combined revenue, net income and primary earnings per
share of the Company and Magma for the twelve months ended December 31, 1995
and 1994, as if the acquisition had occurred at the beginning of 1994 after
giving effect to certain proforma adjustments related to the acquisition were
$400,648, $62,367 and $1.18, compared to $368,276, $30,978 and $.57,
respectively.

4.     Equity Offering

Simultaneous with the acquisition of the remaining equity interest of Magma
on February 24, 1995, the Company completed a public offering (the
"Offering") of 18,170 shares of common stock, which amount included a direct
sale by the Company to Peter Kiewit Sons, Inc. of 1,500 shares and the
exercise of underwriter over-allotment options for 1,500 shares, at a price
of $17.00 per share. The Company received net proceeds of $300,388 from the
Offering.

5.     Debt Offerings

On July 21, 1995 the Company 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, the
Company's interest in a secured Magma note and general assets of the Company
equal to the Restricted Payment Recourse Amount (as defined in the Note
Indenture).

At any time or from time to time on or prior to June 30, 1998, the Company
may, at its option, use all or a portion of the net cash proceeds of a
Company 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
principal amount of the Notes originally issued at a redemption price equal
to 109.875% of the principal amount thereof plus accrued interest to the
redemption date. On or after June 30, 2000, the Notes are redeemable at the
option of the Company, in whole or in part, initially at a redemption price
of 104.9375% declining to 100% on June 30, 2002 and thereafter, plus accrued
interest to the date of redemption.

Concurrent with the issuance of the Notes, the Company through its wholly
owned subsidiary, Salton Sea Funding Corporation ("Funding Corporation"),
completed a sale to institutional buyers of $475,000 principal amount of
Salton Sea Notes and Bonds, which are nonrecourse to the Company. These debt
securities were rated Baa3 by Moody's and BBB- by Standard & Poor's. The
Funding Corporation debt securities were offered in three tranches as
follows:

$232,750 6.69% Senior Secured Series A Notes
   Due May 30, 2000
$133,000 7.37% Senior Secured Series B Bonds
   Due May 30, 2005
$109,250 7.84% Senior Secured Series C Bonds
   Due May 30, 2010

The Salton Sea Notes and Bonds are secured by the Company's three existing
Salton Sea plants, the 40 net MW Salton Sea Unit IV plant 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. In connection with the Salton Sea debt issuance, the
Company has, subject to certain conditions, committed to fund any costs of
construction in connection with the construction of the Salton Sea Unit IV
project over and above the initial budgeted amount of $135,000 in the event
such budgeted amount is insufficient to cause substantial completion of the
expansion project prior to January 1, 1998.

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.

The net proceeds of the Notes and the Salton Sea Notes and Bonds were used to
(a) recapitalize Magma and the related Merger Facilities (b) refinance
approximately $102,000 of existing indebtedness of the Salton Sea Projects,
and (c) provide funding for the Salton Sea Unit IV in the amount of $115,000.
Pursuant to the Depositary Agreement, Funding Corporation established a debt
service reserve fund in the form of a letter of credit in the initial amount
of $50,000 from which scheduled interest and principal payments can be made.

Annual repayment of the Notes and the Salton Sea Notes and Bonds for the
years beginning January 1, 1996 are as follows:

1996                                                  $48,106
1997                                                   64,378
1998                                                   74,938
1999                                                   35,108
2000                                                   19,572
Thereafter                                            409,986

                                                     $652,088


6.     Interest Rate Swap Agreements

In January 1993, the Coso Joint Ventures entered into five year deposit
interest rate swap agreements. The subject deposits represent debt service
reserves established in conjunction with refinancing the Coso Joint Ventures
loans through Coso Funding Corp. The deposit interest rate swaps effectively
convert interest earned on the debt service reserve deposits from a variable
rate to a fixed rate, in order to match the nature of the interest rate on
the borrowings used to fund the debt service reserve deposits. The Company's
proportion of the deposit amount of $25,056 included in restricted cash and
investments accretes annually to a maximum amount of approximately $29,300 in
1997. Under the agreements, which mature on January 11, 1998, the Coso Joint
Ventures make semi-annual payments to the counter party at variable rates
based on LIBOR, reset and compounded every three months, and in return
receive payments based on a fixed rate of 6.34%. The effective LIBOR rate
ranged from 5.6875% to 6.375% during 1995 and was 5.9375% at December 31,
1995. The counter party to these agreements is a large multi-national
financial institution.

In September 1993, the Company entered into a three year deposit interest
rate swap agreement, which effectively converts a notional deposit balance of
$75,000 from a variable rate to a fixed rate. The Company makes semi-annual
payments to the counter party at effectively the LIBOR rate, reset every six
months, and in return receives payments based on a fixed rate of 4.87%. The
counter party to this agreement is the same counter party to the Coso Joint
Ventures.

7.     Properties, Plants, Contracts and Equipment

Properties, plants, contracts and equipment comprise the following at
December 31:
<TABLE>
<CAPTION>

                                                                                   1995              1994
<S>                                                                         <C>                <C> 
Operating project costs:
Power plants                                                                     $623,778          $314,027
Wells and resource development                                                    271,242           174,651
Power sales agreements                                                            185,749               ---
 Licenses, equipment and other                                                     58,052             9,674
Wells and resource development in progress                                            465               434
Total operating facilities                                                      1,139,286           498,786
Less accumulated depreciation and amortization                                  (162,970)          (95,480)
Net operating facilities                                                          976,316           403,306
Mineral reserves                                                                  211,576            39,275
Construction in progress:
   Upper Mahiao                                                                   188,904            48,554
   Malitbog                                                                       146,735               ---
   Mahanagdong                                                                     76,560            21,443
   Salton Sea Unit IV                                                             108,769               ---
   Pacific Northwest geothermal development costs                                  58,311            46,620
   Other international development                                                 11,418             2,445


   Total                                                                       $1,778,589          $561,643


Coso Project Operating Facilities

The Coso Project operating facilities comprise the Company's proportionate
share of the assets of three of its Joint Ventures; Coso Finance Partners
(Navy I Joint Venture), Coso Energy Developers (BLM Joint Venture), and Coso
Power Developers (Navy II Joint Venture).

Navy I Plant

The Navy I Plant consists of three turbines, of which one unit commenced
delivery of firm power in August 1987, and the second and third units in
December 1988. The 80 net MW Plant is located on land owned by and leased
from the U.S. Navy to December 2009, with a 10 year extension at the option
of the Navy. Under terms of the Navy I Joint Venture, profits and losses were
allocated approximately 49% before payout of Units 2 and 3 and approximately
46.4% thereafter to the Company. As of December 31, 1994, payout had been
reached on Units 2 and 3 of the Navy I Plant.

BLM Plant

The BLM Plant consists of two turbines at one site (BLM East), which
commenced delivery of firm power in March and May, 1989, respectively, and
one turbine at another site (BLM West) which commenced delivery of firm power
in August, 1989. The BLM Plant is situated on lands leased from the U.S.
Bureau of Land Management under a geothermal lease agreement that extends
until October 31, 2035. The lease may be extended to 2075 at the option of
the BLM. Under the terms of the BLM Joint Venture agreement, the Company's
share of profits and losses before and after payout is approximately 45% and
48%, respectively. The BLM Plant reached payout in June 1994.

Navy II Plant

The Navy II Plant consists of three turbines, of which two units commenced
delivery of firm power in January 1990, and the third in February 1990. The
80 net MW Plant is located on the southern portion of the Navy lands. Under
terms of the Joint Venture, all profits, losses and capital contributions for
Navy II are divided equally by the two partners.

Imperial Valley Project Operating Facilities

Magma currently operates seven geothermal power plants in the Imperial Valley
in California. Four of these plants were developed by Magma and are owned by
the partnerships in which Magma is the managing general partner and operator
and owns 50% interests. The Partnership Project consists of the Vulcan, Hoch
(Del Ranch), Elmore, and Leather Partnerships. The remaining three plants
which comprise the  Salton Sea Project are wholly owned by subsidiaries of
Magma and were purchased on March 31, 1993 from Union Oil Company of
California. These geothermal power plants consist of the Salton Sea I, Salton
Sea II and the Salton Sea III. The Partnership Project and the Salton Sea
Project are collectively referred to as the 
Imperial Valley Project. The Imperial Valley Project commencement dates and
contract nameplates are as follows:

   Imperial Valley        Commencement                            Contract
   Plants                 Date                                    Nameplate


   Vulcan                 February 10, 1986                       34 MW
   Hoch (Del Ranch)       January 2, 1989                         38 MW
   Elmore                 January 1, 1989                         38 MW
   Leathers               January 1, 1990                         38 MW
   Salton Sea I           July 1, 1987                            10 MW
   Salton Sea II          April 5, 1990                           20 MW
   Salton Sea III         February 13, 1989                       49.8 MW

Significant Customer

All of the Company's sales of electricity from the Coso Project and Imperial
Valley Project, which comprise approximately 93% of 1995 electricity and
steam revenues, are to Edison and are under long-term power purchase
contracts.

The Coso Project and the Partnership Project sell all electricity generated
by the respective plants pursuant to seven long-term SO4 Agreements between
the project and Edison. These SO4 Agreements provide for capacity payments,
capacity bonus payments and energy payments. Edison 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 Edison's Avoided Cost of Energy.

The fixed price periods of the Coso Project 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.

The fixed price periods of the Partnership Project SO4 Agreements extend
until February 1996, December 1998, December 1998, and December 1999 for each
of the Vulcan, Hoch (Del Ranch), Elmore and Leathers Partnerships,
respectively.

The Company's SO4 Agreements provide for rates ranging from 11.4 cents per
kWh in 1995 to 15.6 cents per kWh in 1999.

Salton Sea I sells electricity to Edison pursuant to a 30-year negotiated
power purchase agreement, as amended (the "Salton Sea I PPA"), which provides
for capacity and energy payments. The energy payment is calculated using a
Base Price which is subject to quarterly adjustments based on a basket of
indices. The time period weighted average energy payment for Unit 1 was 4.99 
cents per kWh during 1995. 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 and Salton Sea III sell electricity to Edison pursuant to 30-
year modified SO4 Agreements that provide for capacity payments, capacity
bonus payments and energy payments. The price for contract capacity and
contract capacity bonus payments is fixed for the life of the modified SO4
Agreements. The energy payments for the  first ten year period, which period
expires in April 2000 and February 1999 are levelized at a time period
weighted average of 10.6 cents per kWh and 9.8 cents per kWh for Salton Sea II
and Salton Sea III, respectively. Thereafter, the monthly energy payments will
be Edison's Avoided Cost of Energy. For Salton Sea II only, Edison is entitled
to receive, at no cost, 5% of all energy delivered in excess of 80% of
contract capacity through March 31, 2004.

For the year ended December 31, 1995, Edison's average Avoided Cost of Energy
was 2.1 cents per kWh which is substantially below the contract energy prices
earned for the year ended December 31, 1995. Estimates of Edison's future
Avoided Cost of Energy vary substantially from year to year. The Company
cannot predict the likely level of Avoided Cost of Energy prices under the
SO4 Agreements and the modified SO4 Agreements at the expiration of the
scheduled payment periods. The revenues generated by each of the projects
operating under SO4 Agreements could decline significantly after the
expiration of the respective scheduled payment periods.

Royalty Expense

Royalty expense comprises the following for the years ended:

                                 1995              1994              1993


Navy I, Unit 1                  $ 1,622            $1,641            $1,556
Navy I, Units 2 and 3             3,394             3,174             2,924
BLM                               3,036             2,842             1,868
Navy II                           5,571             1,963             1,717
WSG                                 287               268               209
Vulcan                            1,207               ---               ---
Leathers                          1,968               ---               ---
Elmore                            1,713               ---               ---
Hoch (Del Ranch)                  1,932               ---               ---
Salton Sea 1 & 2                  1,147               ---               ---
Salton Sea 3                      2,431               ---               ---


   Total                        $24,308            $9,888            $8,274


The amount of royalties paid by Navy I to the U.S. Navy to develop geothermal
energy for Navy I, Unit 1 on the lands owned by the Navy comprises (i) a fee
payable during the term of the contract based on the difference between the
amounts paid by the Navy to Edison for specified quantities of electricity
and the price as determined under the contract (which currently approximates
73% of that paid by the Navy to Edison), and (ii) $25,000 payable in December
2009, of which the Company's share is $11,600. The $25,000 payment is secured
by funds placed on deposit monthly, which funds, plus accrued interest, will
aggregate $25,000. The monthly deposit is currently $50. As of December 31,
1995, the balance of funds deposited approximated $4,457, which amount is
included in restricted cash and accrued liabilities.

Units 2 and 3 of Navy I and the Navy II power plants are on Navy lands, for
which the Navy receives a royalty based on electric sales revenue at the
initial rate of 4% escalating to 22% by the end of the contract in December
2019. The BLM is paid a royalty of 10% of the value of steam produced by the
geothermal resource supplying the BLM Plant.

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

The Salton Sea Project's weighted average royalty expense in 1995 was
approximately 3.4%. The royalties are paid to numerous recipients based on
varying percentages of electrical revenue or steam production multiplied by
published indices.

Yuma Project

During 1992, the Company acquired a development stage 50 net MW natural gas-
fired cogeneration project in Yuma, Arizona (the "Yuma Project"). The Yuma
Project is designed to be a Qualifying Facility ("QF") under PURPA and to
provide 50 net MW of electricity to San Diego Gas & Electric Company
("SDG&E") under an existing 30-year power purchase contract. The electricity
is sold at SDG&E's Avoided Cost of Energy. 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.

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 contract 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.

Mineral Reserves - Nevada and Utah Properties

On May 3, 1990, the Company entered into a definitive purchase agreement with
a subsidiary of Chevron Corporation ("Chevron") for the acquisition of
certain geothermal operations, including interests in approximately 83,750
acres of geothermal properties in Nevada and Utah, for an aggregate purchase
price of approximately $51,100. These property interests consist largely of
leasehold interests, including properties leased from the BLM and from
private landowners.

The property acquired from Chevron includes:

Roosevelt Hot Springs. The Company operates and owns an approximately 70%
interest in a geothermal steam field which supplies geothermal steam to a 23
net MW power plant owned by Utah Power & Light Company ("UP&L") located on
the Roosevelt Hot Springs property under a 30-year steam sales contract. The
Company obtained approximately $20,317 cash under a pre-sale  agreement with
UP&L whereby UP&L paid in advance for the steam produced by the steam field.
The Company must make certain penalty payments to UP&L if the steam produced
does not meet certain quantity and quality requirements.

Desert Peak. The Company is the owner and operator of a 10 net MW geothermal
plant at Desert Peak, Nevada that is currently selling electricity to Sierra
Pacific Power Company ("Sierra") under a power sales agreement that expires
December 31, 1995 and that may be extended on a year-to-year basis as agreed
by the parties. The December 31, 1995 price for electricity under this
contract was 6.6 cents per kWh, comprising an energy payment of 2.1 cents per 
kWh (which is adjustable pursuant to an inflation-based index) and a capacity
payment of 4.5 cents per kWh. The Company is currently selling power to Sierra
at Sierra's Avoided Cost.

Pacific Northwest Geothermal Development Costs

In the Pacific Northwest, the Company has acquired leasehold rights and has
performed certain geological evaluations to determine the resource potential
of the underlying properties. Recovery of those costs is ultimately dependent
upon the Company's ability to prove geothermal reserves and sell geothermal
steam, or to obtain financing, build power plants, gain access to high
voltage transmission lines, and sell the resultant electricity at favorable
prices or, sell its leaseholds. In the opinion of management, the Company
will be able to recover its development costs through the generation of
electricity for sale. In September 1994, the Company executed the final Power
Purchase Agreements with Bonneville Power Administration ("BPA") and Eugene
Water and Electric Board ("EWEB") for a 30 MW geothermal pilot project
planned to be constructed at the Newberry site near Bend, Oregon. The Company
agreed to sell 20 net MW to BPA and 10 net MW to Eugene Water and Electric
Board ("EWEB") from the Newberry Project. In addition, BPA and EWEB together
have an option to purchase up to an additional 100 net MW of production from
the Newberry Project under certain circumstances. In a public-private
development effort, the Company is responsible for development, permitting,
financing, construction and operation of the project (which will be 100%
owned by the Company), while EWEB will cooperate in the development efforts
by providing assistance with government and community affairs and sharing in
the development costs (up to 30%). The Newberry Project is currently expected
to commence commercial operation in 1998. The power sales agreements provide
that under certain circumstances the contracts may be utilized at an
alternative location. Completion of the Newberry Project is subject to a
number of significant uncertainties and cannot be assured.

SFAS 121

On January 1, 1996, the Company intends to adopt 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." Management
anticipates that the adoption of SFAS 121 will not have a material effect on
the Company's financial statements.

8.     Equity Investment in Casecnan

The Company has a 35% ownership interest in the Casecnan Project, a
multipurpose irrigation and hydroelectric power facility with a rated
capacity of approximately 150 net MW located on the island  of Luzon in the
Philippines. The assets and liabilities of the Casecnan Project as of
December 31, 1995 were $500,672 and $378,299 respectively.

9.     Project Loans

Project loans, which are nonrecourse to the Company, comprise the following
at December 31:


</TABLE>
<TABLE>
<CAPTION>
                                                                  1995      1994

<S>                                                             <C>       <C>
Coso Funding Corp. project loans with fixed interest rates
(weighted average interest rates of 8.29% and 8.13% at
December 31, 1995 and 1994, respectively) with scheduled
repayments through December 2001                                $203,226  $233,080

Partnership Project loans with variable interest rates
(weighted average interest rates of 6.44% at December 31,
1995) and scheduled repayments through September 2002             54,707       ---


   Total Project Loans                                          $257,933  $233,080

</TABLE>

The Coso Funding Corp. project loans are from Coso Funding Corp. ("Funding
Corp."). Funding Corp. is a single-purpose corporation formed to issue notes
for its own account and as an agent acting on behalf of the Coso Project. On
December 16, 1992, pursuant to separate credit agreements executed between
Funding Corp. and each Coso Joint Venture the proceeds from Funding Corp.'s
note offering were loaned to the Coso Project. The proceeds of $560,245 were
used by the Coso Project to (i) purchase and retire project finance debt
comprised of the term loans and construction loans in the amount of $424,500,
(ii) fund contingency funds in the amount of $68,400, (iii) fund debt service
reserve funds in the amount of $40,000, and (iv) finance $27,345 of capital
expenditures and transaction costs. The contingency fund and debt service
reserve fund were required by the project loan agreements.

The contingency fund represented the approximate maximum amount, if any,
which could theoretically have been payable by the Coso Project to third
parties to discharge all liens of record and other contract claims
encumbering the Coso Project's plants at the time of the project loans. The
contingency fund was established in order to obtain investment-grade ratings
to facilitate the offer and sale of the notes by Funding Corp., and such
establishment did not reflect the Coso Project's view as to the merits or
likely disposition of such litigation or other contingencies. On June 9,
1993, MPE and the Mission Power Group, subsidiaries of Edison Corp., and the
Coso Project reached a final settlement of all of their outstanding disputes
and claims relating to the construction of the Coso Project. As a result of
the various payments and releases involved in such settlement, the Coso
Project agreed to make a net payment of $20,000 to MPE from the cash reserves
of the Coso Project contingency fund and MPE agreed to release its mechanics'
liens on the Coso Project. After making the $20,000 payment, the remaining
balance of the Coso Project contingency fund (approximately $49,300) was used
to increase the Coso Project debt reserve fund from approximately $43,000 to
its maximum fully-funded requirement of $67,900. The remaining $24,400
balance of contingency fund was retained within the Coso Project for future
capital expenditures and for Coso Project debt service payments. Since the
Coso Project debt service reserve is fully funded in advance, Coso Project
cash flows otherwise intended to fund the Coso Project debt service reserve
fund, subject to  satisfaction of certain covenants and conditions contained
in the Coso Joint Ventures' refinancing documents, may be available for
distribution to the Company in its proportionate share.

The Funding Corp. project loans are collateralized by, among other things,
the power plants, geothermal resource, debt service reserve funds,
contingency funds, pledge of contracts, and an assignment of all such Coso
Project's revenues which will be applied against the payment of obligations
of each Coso Joint Venture, including the project loans. Each Coso Joint
Venture's assets will secure only its own project loan, and will not be
cross-collateralized with assets pledged under other Coso Joint Venture's
credit agreements. The project loans are nonrecourse to any partner in the
Coso Joint Ventures and Funding Corp. shall solely look to such Coso Joint
Venture's pledged assets for satisfaction of such project loans. However, the
loans are cross-collateralized by the available cash flow of each Coso Joint
Venture. Each Coso Joint Venture after satisfying a series of its own
obligations has agreed to advance support loans (to the extent of available
cash flow and, under certain conditions, its debt service reserve funds) in
the event revenues from the supporting Coso Joint Ventures are insufficient
to meet scheduled principal and interest on their separate project loans.

Partnership Project loans include the Company's pro-rata share of the debt of
the Del Ranch, Elmore, and Leathers partnerships and is nonrecourse to the
Company and subsidiaries, however, it is collateralized by substantially all
of the assets of these partnerships. A Secured Credit Agreement with a group
of international banks, with Morgan Guaranty Trust Company ("Morgan") as the
agent bank provides for direct bank loans at specified premiums over a choice
of either the bank's prime rate, the London Interbank Offered Rate ("LIBOR")
or the CD Base rate. As an alternative, each partnership may elect to issue
commercial paper and medium-term notes supported by letters of credit issued
by Fuji Bank, Limited, which are secured, in turn, by the project debt
facility with the Company. The partnerships had no direct bank borrowings at
December 31, 1995. The loans of each partnership are reduced by semiannual
principal payments in March and September of each year. The last principal
payment is scheduled for September 15, 2001 for the Del Ranch and Elmore
loans and September 15, 2002 for the Leathers loan.

The annual repayments of the project loans for the years beginning January 1,
1996 and thereafter are as follows:

                         Coso              Partnership
                     Funding Corp.           Project            Total 


1996                    $54,881              $12,831           $67,712
1997                     41,729               13,347            55,076
1998                     38,912               13,347            52,259
1999                     31,717                8,578            40,295
2000                      4,080                2,953             7,033
Thereafter               31,907                3,651            35,558

                       $203,226              $54,707          $257,933

10.    Construction Loans


The Construction Loans which are nonrecourse to the Company, comprise the
following at December 31:

<TABLE>
<CAPTION>

                                                                1995        1994

<S>                                                          <C>            <C>
Upper Mahiao Construction Loan with variable interest 
rates (weighted average interest rate of 8.31%) with 
scheduled project term repayments through 2006               $134,619       $24,508

Mahanagdong Construction Loan with variable interest
rates (weighted average interest rate of 8.02%) with
scheduled project term repayments through 2007                 39,716         6,995

Malitbog Construction Loan with variable interest 
rates (weighted average interest rate of 8.42%) with
scheduled project term repayments through 2005                 36,863           ---

                                                             $211,198       $31,503

</TABLE>

Draws on the construction loan and accrued liabilities for the Upper Mahiao
geothermal power project at December 31, 1995 totalled $134,619 and $2,313,
respectively. A syndicate of international commercial banks is providing the
construction financing with interest rates at LIBOR or "Prime" with interest
payments due every quarter and at LIBOR maturity. The weighted average
interest rate at December 31, 1995 is approximately 8.31%. The Export-Import
Bank of the U.S. ("Ex-Im Bank") is providing political risk insurance to
commercial banks on the construction loan and will provide the majority of
the project term financing of approximately $162,000 upon satisfaction of the
conditions associated with commercial operation. The term financing for the
Ex-Im Bank loan will be for a ten-year term at a fixed interest rate of
5.95%. The accrued liabilities represent invoices which were received, but
not paid, by December 31, 1995 and retention on the construction and supply
contracts.

The Company's share of draws on the construction loan and accrued liabilities
for the Mahanagdong geothermal power project at December 31, 1995 totalled
$39,716 and $6,592 respectively. The construction debt financing is provided
by the Overseas Private Investment Corporation ("OPIC") and a consortium of
commercial lenders led by Bank of America NT&SA. The construction loan
interest rates are at LIBOR or "Prime" with interest payments due quarterly
and at LIBOR maturity. The debt provided by the commercial lenders will be
insured by Ex-Im Bank against political risks. Ten-year project term debt
financing of approximately $120,000 will be provided by Ex-Im Bank (which
will replace the bank construction debt) and by OPIC. The majority of the
term financing is expected to be provided by the Ex-Im Bank at a fixed
interest rate of 6.92%. The accrued liabilities represent invoices which were
received, but not paid, by December 31, 1995 and retention on the
construction and supply contracts.

Draws on the construction loan and accrued liabilities for the Malitbog
Geothermal Power Project at December 31, 1995 totalled $36,863 and $18,678,
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 OPIC against political risks and the Company's equity contribution
to Visayas Geothermal Power Company ("VGPC") is covered by political risk
insurance from the Multilateral Investment Guarantee Agency and OPIC.

11.    Senior Discount Notes

In March 1994, the Company issued $400,000 of 10 1/4% Senior Discount Notes
which accrete to an aggregate principal amount of $529,640 at maturity in
2004. The original issue discount (the difference between $400,000 and
$529,640) will be amortized from issue date through January 15, 1997, during
which time no cash interest will be paid on the  Senior Discount Notes.
Commencing July 15, 1997, cash interest on the Senior Discount Notes will be
payable semiannually on January 15 and July 15 of each year. The Senior
Discount Notes are redeemable at any time on or after January 15, 1999. The
redemption prices commencing in the twelve month period beginning January 15,
1999 (expressed in percentages of the principal amount) are 105.125%,
103.417%, 101.708%, and 100% for 1999, 2000, 2001, and 2002, respectively,
plus accrued interest through the redemption date in each case. 
The Senior Discount Notes are unsecured senior obligations of the Company.

The Senior Discount Notes prohibit payment of cash dividends unless certain
financial ratios are met and the dividends do not exceed 50% of the Company's
accumulated adjusted consolidated net income as defined, subsequent to April
1, 1994, plus the proceeds of any stock issuance.

12.    Convertible Subordinated Debentures

In June of 1993, the Company issued $100,000 principal amount of 5%
convertible subordinated debentures ("debentures") due July 31, 2000. The
debentures are convertible into shares of the Company's common stock at any
time prior to redemption or maturity at a conversion price of $22.50 per
share, subject to adjustment in certain circumstances. Interest on the
debentures is payable semi-annually in arrears on July 31 and January 31 of
each year, commencing on July 31, 1993. The debentures are redeemable for
cash at any time on or after July 31, 1996 at the option of the Company. The
redemption prices commencing in the twelve month period beginning July 31,
1996 (expressed in percentages of the principal amount) are 102%, 101%, 100%
and 100% in 1996, 1997, 1998 and 1999, respectively. The debentures are
unsecured general obligations of the Company and subordinated to all existing
and future senior indebtedness of the Company.

13.    Exchange of Preferred Stock to Convertible Debt

On November 19, 1991, the Company sold one thousand shares of convertible
preferred stock, Series C, at $50,000 per share to Kiewit Energy Company, in
a private placement. Each share of the Series C preferred stock was
convertible at any time at $18.375 per common share into two thousand seven
hundred and twenty-one shares of common stock subject to customary
adjustments. The Series C preferred stock had a dividend rate of 8.125%,
commencing March 15, 1992 through conversion date or December 15, 2003. The
dividends, which were cumulative, were payable quarterly in convertible
preferred stock, Series C, through March 15, 1995 and in cash on subsequent
dividend dates.

Pursuant to the terms of the Securities Purchase Agreement, the Company
exercised its rights to exchange the preferred stock, Series C, on March 15,
1995 for $64,850 principal amount 9.5% convertible subordinated debenture of
the Company due 2003, with the same conversion features of the preferred
stock, Series C.

The Company is obligated to redeem 20% of the outstanding debt each December
15, commencing 1999 through 2003, plus accrued interest.

At any time after March 15, 1995, upon 20 days notice, the Company may redeem
all, or any portion consisting of at least $5,000, of the convertible debt,
then outstanding, provided that the Company's common stock has traded at or
above 150% of the then effective conversion price, for  any 20 trading days
out of 30 consecutive trading days ending not more than five trading days
prior to notice of redemption.

14.    Income Taxes

On January 1, 1993, the Company adopted Statement of Financial Accounting
Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes." The adoption
of SFAS 109 changed the Company's method of accounting for income taxes from
the deferred method as required by Accounting Principles Board Opinion No. 11
to an asset and liability approach. Under SFAS 109, the net excess deferred
tax liability as of January 1, 1993 was determined to be $4,100. This amount
was reflected in 1993 income as the cumulative effect of a change in
accounting principle. It primarily represents the recognition of the
Company's tax credit carryforwards as a deferred tax asset. There was no cash
impact to the Company upon the required adoption of SFAS 109. Under SFAS 109,
the effective tax rate increased to approximately 30% in 1993 from 23.5% in
1992. This increase was due to the Company's tax credit carryforward being
recognized as an asset and unavailable to reduce the current period's
effective tax rate for computing the Company's provision for income taxes.

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

                                   1995            1994            1993

Currently payable:
State                           $ 5,510         $ 1,970         $ 3,300
Federal                          11,138           5,829           7,686

                                 16,648           7,799          10,986

Deferred:
State                               921           1,017             385
Federal                          13,062           7,241           6,813

                                 13,983           8,258           7,198

Total after benefit of 
   extraordinary item            30,631          16,057          18,184

Tax benefit attributable to
   extraordinary item               ---             945             ---

Total before benefit of
   extraordinary item           $30,631         $17,002         $18,184



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:

<TABLE>
<CAPTION>
                                                                     1995           1994             1993 

<S>                                                                <C>            <C>              <C>
Federal statutory rate                                              35.00  %       35.00  %         35.00  %
Percentage depletion in excess
   of cost depletion                                                (7.38)         (6.85)           (6.70)
Investment and energy tax credits                                   (1.80)         (3.04)           (4.62)
State taxes, net of federal tax effect                               4.09           4.48             3.90 
Cumulative effect of change in
   federal tax rate                                                   ---            ---             1.90 
Goodwill amortization                                                2.53            ---              --- 
Non-Deductible Expense                                               1.10            ---              --- 
Lease investment                                                    (2.18)           ---              --- 
Other                                                                 .20            .86              .20 


                                                                    31.56  %       30.45  %         29.68  %

</TABLE>

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

                                                1995               1994  


Depreciation and amortization, net           $349,079          $119,947 
Other                                           4,043             3,590 

                                              353,122           123,537 

Deferred income                                (7,709)           (2,190)
Loss carryforwards                             (3,050)          (31,592)
Energy and investment tax credits             (52,857)          (40,748)
Alternative minimum tax credits               (52,480)          (22,379)
Jr. SO4 royalty receivable                     (5,865)              --- 
Other                                          (4,641)              (60)

                                             (126,602)          (96,969)

Net deferred taxes                           $226,520           $26,568 


As of December 31, 1995, the Company has an unused net operating loss (NOL)
carryover of approximately $8,714 for regular federal tax return purposes
which expires in 2007. In addition, the Company has unused investment and
geothermal energy tax credit carryforwards of approximately $52,857 expiring
between 2002 and 2010. The Company also has approximately $52,480 of
alternative minimum tax credit carryforwards which have no expiration date.

15.    Preferred Stock

Series A:

On December 1, 1988, the Company distributed a dividend of one preferred
share purchase right ("right") for each outstanding share of common stock.
The rights are not exercisable until ten days after a person or group
acquires or has the right to acquire, beneficial ownership of 20% or more of
the Company's common stock or announces a tender or exchange offer for 30% or
more of the Company's common stock. Each right entitles the holder to
purchase one one-hundredth of a share of Series A junior preferred stock for
$52. The rights may be redeemed by the Board of Directors up to ten days
after an event triggering the distribution of certificates for the rights.
The rights plan was amended in February 1991 so that the agreement with
Kiewit Energy (see Note 12) would not trigger the exercise of the rights. The
rights will expire, unless previously redeemed or exercised, on November 30,
1998. The rights are automatically attached to, and trade with, each share of
common stock.

16.    Stock Options and Restricted Stock

The Company has issued various stock options. As of December 31, 1995, a
total of 9,552 shares are reserved for stock options, of which 9,291 shares
have been granted and remain outstanding at prices of $3.00 to $19.00 per
share.

The Company has stock option plans under which shares were reserved for grant
as incentive or non-qualified stock options, as determined by the Board of
Directors. The plans allow options to be granted at 85% of their fair market
value at the date of grant. Generally, options are issued at 100% of fair
market value at the date of grant. Options granted under the 1986 Plan become
exercisable over a period of three to five years and expire if not exercised
within ten years from the date of grant or, in some instances a lesser term.
Prior to the 1986 Plan, the Company granted 256 options at fair market value
at date of grant which had terms of ten years and were exercisable at date of
grant. In addition, the Company had issued approximately 138 options to
consultants on terms similar to those issued under the 1986 Plan. The non-
1986 plan options are primarily options granted to Kiewit Energy; see Note
17.

On January 1, 1996, the Company intends to adopt the disclosure requirements
of Statement of Financial  Accounting Standards No. 123 ("SFAS 123"),
"Accounting for Stock-Based Compensation." Management anticipates that
adoption of SFAS 123 will not have a material effect on the Company's
financial statements.

The Company granted 500 shares of restricted common stock with an aggregate
market value of $9,500 in exchange for the relinquishment of 500 stock
options which were cancelled by the Company. The shares have all rights of a
shareholder, subject to certain restrictions on transferability and risk of
forfeiture. Unearned compensation equivalent to the market value of the
shares at the date of issuance was charged to Stockholders' equity. Such
unearned compensation is being amortized over the vesting period of which 125
shares were immediately vested and the remaining 375 shares vest straight-
line over five years. Accordingly, $2,494 of unearned compensation was
charged to general and administrative expense in 1995.

Transactions in Stock Options

<TABLE>
<CAPTION>
                                                                                  Options Outstanding   
                                             Shares Available
                                             for Grant Under                           Option Price  
                                             1986 Option Plan         Shares             Per Shares               Total  

<S>                                           <C>                  <C>                 <C>                     <C>
Balance December 31, 1992                         816               7,397*          $3.00 - $ 15.938            $ 80,021 
Options granted                                (1,396)              1,396          $17.75 - $ 19.00               26,209 
Options terminated                                 19                 (20)          $3.00 - $ 14.875                (114)
Options exercised                                 ---                (259)          $3.00 - $ 14.875              (1,185)
Additional shares reserved
   under 1986 Option Plan                       1,000                 ---                 ---                        --- 


Balance December 31, 1993                         439               8,514*           $3.00 - $19.00              104,931 


Options granted                                  (954)              1,243            $16.00 - $17.25              19,260 
Options terminated                                 15                 (15)           $3.00 - $15.938                (205)
Options exercised                                 ---                (141)           $3.00 - $15.938                (709)
Additional shares reserved
   under 1986 Option Plan                         586                 ---                 ---                        --- 

Balance December 31, 1994                          86               9,601*           $3.00 - $19.00             123,277 

Options granted                                  (396)                396            $15.81 - $19.00              17,188 
Options terminated                                571                (571)          $14.875 - $19.00             (10,673)
Options exercised                                 ---                (135)           $3.00 - $15.938                (460)


Balance December 31, 1995                         261               9,291*            $3.00 - $19.00            $119,332 


Options which became exercisable during:
          Year ended December 31, 1995                               985            $12.63 - $ 19.00             $17,512
          Year ended December 31, 1994                             1,015           $11.625 - $ 19.00             $15,776
          Year ended December 31, 1993                               592            $ 3.00 - $ 19.00             $10,180
Option exercisable at:
          December 31, 1995                                        8,229*           $ 3.00 - $ 19.00            $100,886
          December 31, 1994                                        7,897*           $ 3.00 - $ 19.00            $ 93,705
          December 31, 1993                                        7,026*           $ 3.00 - $ 19.00            $ 78,644

</TABLE>

*Includes Kiewit Energy options.  See Note 17.

17.    Common Stock Sales & Related Options

The Company and Kiewit Energy Company, Inc. ("Kiewit") signed a Stock Purchase
Agreement and related agreements, dated as of February 18, 1991. Kiewit is a
subsidiary of Peter Kiewit Sons', Inc. of Omaha, Nebraska, a large construction,
mining, and telecommunications company with diversified operations. Under the
terms of the agreements, Kiewit purchased 4,000 shares of common stock at $7.25
per share and received options to buy 3,000 shares at a price of $9 per share
exercisable over three years and an additional 3,000 shares at a price of $12 
per share exercisable over five years (subject to customary adjustments).

In May 1994, pursuant to a special antidilution provision of the 1991 Stock
Purchase Agreement between the Company and Kiewit, the Company increased 
Kiewit's existing option (granted in 1991) to purchase 3,000 shares at $12 per
share by an additional 289 shares as a final adjustment under such provisions.

In connection with this initial stock purchase, the Company and Kiewit also
entered into certain other agreements pursuant to which (i) Kiewit and its
affiliates agreed not to acquire more than 34% of the outstanding common stock
(the "Standstill Percentage") for a five-year period, (ii) Kiewit became 
entitled to nominate at least three of the Company's directors, and (iii) the
Company and Kiewit agreed to use their best efforts to negotiate and execute a 
joint venture agreement relating to the development of certain geothermal 
properties in Nevada and Utah.

On June 19, 1991, the board approved a number of amendments to the Stock 
Purchase Agreement and the related agreements. Pursuant to those amendments, the
Company reacquired from Kiewit the rights to develop the Nevada and Utah 
properties, and Kiewit agreed to exercise options to acquire 1,500 shares of
common stock at $9.00 per share, providing the Company with $13,500 in cash.
The Company also extended the term of the $9.00 and $12.00 options to seven 
years; modified certain of the other terms of these options; granted to Kiewit
an option to acquire an additional 1,000 shares of the common stock at $11.625
per share (closing price for the shares on the American Stock Exchange on June
18, 1991) for a ten year term; and increased the Standstill Percentage from 34% 
to 49%. 

On November 19, 1991, the Board approved the issuance by the Company to Kiewit
of one thousand shares of Series C preferred stock for $50,000, as described in
Note 13. In connection with the sale of the Series C preferred stock to Kiewit,
the Standstill Agreement was amended so that the 49% Standstill Percentage
restriction would apply to voting stock rather than just common stock.

18.    Litigation

As of December 31, 1995 there were no material outstanding lawsuits.

19.    Related Party Transactions

The Company charged and recognized a management fee and interest on advances to
its Coso Joint Ventures, which aggregated approximately $6,075, $5,569 and 
$5,354 in the years ended December 31, 1995, 1994 and 1993. The Company's note
receivable from the Coso Joint Ventures bears a fixed interest rate of 12.5% and
is payable on or before March 19, 2002. This note is subordinated to the senior
project loan on the project.

The Company's wholly owned subsidiaries charge and recognize a management,
operator, guaranteed capacity and brine fee to its Partnership Project. A
management and operator fee is also charged to the Salton Sea Project. These 
fees aggregated approximately $50,793 for the year ended December 31, 1995.

The Mahanagdong Project is being constructed by a consortium (the "EPC
Consortium") of Kiewit Construction Group, Inc. ("KCG") and the CE Holt Company,
a wholly owned subsidiary of the Company, 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. The Mahanagdong EPC provides for maximum liability for
liquidated damages of up to $100,500 and total liability of up to $201,000. KCG,
a wholly owned subsidiary of Peter Kiewit Sons', Inc. ("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.  CE Holt Company will provide design and engineering services
for the EPC Consortium, and holds a 20% interest. The Company has provided a 
guaranty of CE Holt Company's obligations under the Mahanagdong EPC Contract.

The Company participates in an international joint venture agreement with PKS
which the Company believes enhances its capabilities in foreign power markets.
The joint venture agreement is limited to international activities and provides
that if both the Company and PKS agree to participate in a project, they will
share all development costs equally. Each of the Company and PKS will provide 
50% of the equity required for financing a project developed by the joint 
venture and the Company will operate and manage such project. 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, and equal equity participant and PKS will be 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.

20.    Extraordinary Item

In conjunction with the Company's Senior Discount Note offering in 1994 (See 
Note 11), the 12% Senior Notes were defeased. This resulted in an extraordinary
item in the amount of $2,007, after the income tax effect of $945. The extra-
ordinary item represents the amount necessary to defease the interest payments
and the unamortized portion of the deferred financing costs on the $35,730 
Senior Notes.

21.    Fair Value of Financial Instruments

Statement of Financial Accounting Standards ("SFAS") No. 107, "Disclosures about
Fair Value of Financial Instruments," requires disclosure of the following
information about the fair value of certain financial instruments for which it
is practicable to estimate that value. For purposes of the following disclosure,
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 judgement 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. The fair value of convertible
debt (see Note 13) is not practicable to estimate due to the convertible 
features of the debt.

Interest rate swap agreements - The fair value of interest rate swap agreements
is estimated based on quotes from the counter party to these instruments and
represents the estimated amounts that the Company would expect to receive or pay
to terminate the agreements. It is the Company's intention to hold the swap
agreements to their intended maturity.

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 except for the interest rate swaps which are
discussed in Note 6.

22.    QUARTERLY FINANCIAL DATA (UNAUDITED)

Following is a summary of the Company's quarterly results of operations for the
years ended December 31, 1995 and December 31, 1994.

<TABLE>
<CAPTION>

                                                    Three Months Ended *
1995: (1)                              March 31      June 30     September 30    December 31
<S>                                    <C>           <C>          <C>               <C>
Revenue:
Sales of electricity and steam         $72,978       $81,756      $102,423          $78,473
Royalties                                3,917         4,912         5,372            5,281 
Other income                             9,790        10,428        11,922           11,471 

Total revenue                           86,685        97,096       119,717           95,225
Total costs and expenses                68,527        76,957        79,898           76,290

Income before provision for income
  taxes and monority interestm          18,158        20,139        39,819           18,935
Provision for income taxes               5,540         6,248        12,457            6,386

Net incoe before minority interest      12,618        13,891        27,362           12,549

Minority interest                        3,005           ---           ---              ---
Net income                               9,613        13,891        27,362           12,549 
Preferred dividends                      1,080           ---           ---              --- 

Net income attributable to common
  shares                               $ 8,533       $13,891       $27,362          $12,549 

Net income per share - primary         $   .21       $   .27       $   .52          $   .24

Net income per share - fully diluted   $   .21       $   .27       $   .48          $   .18  

1994:                                  March 31      June 30       September 30     December 31    

Revenue:
Sales of electricity and steam        $30,819        $36,850       $49,498          $37,395 
Other income                            4,591          8,404         9,026            9,271

Total revenue                          35,410         45,254        58,524           46,666
Total costs and expenses               22,753         33,198        37,771           36,296

Income before provision for income
  taxes                                12,657         12,056        20,753           10,370
Provision for income taxes              4,050          3,677         6,340            2,935

Net income before extraordinary item    8,607          8,379        14,413            7,435
Extraordinary item (2)                 (2,007)           ---           ---              ---

Net income                              6,600          8,379        14,413            7,435
Preferred dividends                     1,200          1,236         1,275            1,299

Net income attributable to common
  shares                              $ 5,400        $ 7,143       $13,138          $ 6,136 

Net income per share before
  extraordinary item                  $   .20        $   .20       $   .38          $   .18
Net income per share-extraordinary  
  item (2)                               (.06)           ---           ---              ---

Net income per share - primary        $   .14       $    .20       $   .38          $   .18

Net income per share - fully diluted  $   .14       $    .20       $   .36          $   .18 

</TABLE>
*    percentage of income earned in the second and third quarters.
(1)  Reflects acquisition of Magma, see Note 3.
(2)  See Note 20.


INDEPENDENT Auditors' Report

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

We have audited the accompanying consolidated balance sheets of CalEnergy
Company, Inc. and subsidiaries as of December 31, 1995 and 1994, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1995.
These financial statements are the responsibility of the Company's 
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of CalEnergy Company, Inc. and
subsidiaries at December 31, 1995 and 1994 and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1995, in conformity with generally accepted accounting
principles.

As discussed in Note 14, the consolidated financial statements give effect to
the Company's adoption, effective January 1, 1993, of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes."

Deloitte & Touche LLP
Omaha, Nebraska
January 26, 1996