MID AMERICAN ENERGY HOLDINGS CO /NEW/, 10-K, 1999-03-31

MID AMERICAN ENERGY HOLDINGS CO /NEW/
10-K, 1999-03-31
ELECTRIC, GAS & SANITARY SERVICES

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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 1998
Commission File No. 1-9874

MIDAMERICAN ENERGY HOLDINGS COMPANY
(the successor in interest to CalEnergy Company, Inc.)
(Exact name of registrant as specified in its charter)

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

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

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

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

Name of exchange
Title of each class on which registered
Common Stock, No New York Stock Exchange
par value ("Common Stock") Pacific Stock Exchange
London Stock Exchange

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

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

Yes X No

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

Based on the closing sales price of Common Stock on the New York
Stock Exchange on March 29, 1999 the aggregate market value of the
Common Stock held by non-affiliates of the Company was $1,644,091,283.

58,848,905 shares of Common Stock were outstanding on March 29,
1999.

DOCUMENTS INCORPORATED BY REFERENCE

Incorporated by reference into this Form 10-K, in response to Item 3
Part I, Items 6 through 8 of Part II and Items 10 through 13 of Part
III, are the portions indicated herein of (i) the annual report of
CalEnergy Company, Inc. (the "Company") to security holders for the
fiscal year ended December 31, 1998 (the "Annual Report"), and (ii) the
Company's proxy statement dated on or about April 3, 1999 for the
annual meeting of stockholders to be held on May 20, 1999 (the "Proxy
Statement").

<PAGE>
TABLE OF CONTENTS

PART I 1
ITEM 1. BUSINESS 1
GENERAL 2
RECENT ACQUISITIONS 2
STRATEGY 3
THE GLOBAL ENERGY MARKET 6
THE UNITED STATES 6
THE UNITED KINGDOM 8
THE COMPANY'S DISTRIBUTION AND SUPPLY BUSINESS 10
MIDAMERICAN ENERGY COMPANY 10
NORTHERN ELECTRIC 13
PROJECTS IN OPERATION 17
UNITED STATES POWER GENERATION 17
MIDAMERICAN ENERGY GENERATION FACILITIES 17
CE GENERATION GAS FACILITIES 19
OTHER U.S. GEOTHERMAL INTERESTS 21
UNITED KINGDOM POWER GENERATION 21
THE PHILIPPINES POWER GENERATION 21
PROJECTS IN CONSTRUCTION 24
UNITED STATES 24
PHILIPPINES 24
INDONESIA 26
PROJECTS IN DEVELOPMENT 26
UNITED STATES 26
UNITED KINGDOM 27
PRODUCING GAS FIELD OPERATIONS AND FIELDS IN DEVELOPMENT 27
THE COMPANY'S PRODUCING GAS FIELD OPERATIONS AND FIELDS IN
DEVELOPMENT 28
PROJECTS FIELDS IN DEVELOPMENT 29
REGULATORY, ENERGY AND ENVIRONMENTAL MATTERS 29
UNITED STATES 30
UNITED KINGDOM 31
EMPLOYEES 32
ITEM 2.PROPERTIES 32
ITEM 3. LEGAL PROCEEDINGS 33
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 33
PART II 34
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER'S MATTERS 34
ITEM 6. SELECTED FINANCIAL DATA 36
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 36
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET
RISK 36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 36
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 36
PART III 37
MANAGEMENT 37
ITEM 10. DIRECTORS, EXECUTIVE AND OTHER OFFICERS OF THE COMPANY
AND SIGNIFICANT SUBSIDIARIES 37
PART IV 44
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K 44
SIGNATURES 46
EXHIBIT INDEX 48
<PAGE>
PART I

Item 1. Business

General

MidAmerican Energy Holdings Company, the successor in
interest to CalEnergy Company, Inc. (the "Company" or "MEHC"), is
a fast-growing global energy company with an increasingly
diversified portfolio of regulated and non-regulated assets. The
focus of the Company has evolved over time from development and
acquisition activities in the domestic and international power
generation markets to strategic electric and gas utility
acquisitions, with a particular emphasis on investment-grade
countries such as the United States, the United Kingdom,
Australia, Canada, New Zealand and certain of the countries of
Western Europe. This focus has provided the Company with
increased scale, skill, revenue diversity, credit quality,
quality of cash flows and growth opportunities associated with
each of the acquired businesses. The Company was founded in 1971
and, through its subsidiaries, manages and owns interests in over
10,000 megawatts ("MW") in 33 power generation facilities in
operation, construction and development worldwide. In addition,
through its subsidiaries, MidAmerican Energy Company
("MidAmerican Energy" or "MEC") and Northern Electric plc
("Northern"), the Company currently serves more than 3.37 million
customers worldwide (2.15 million electricity customers and 1.22
million natural gas customers) following the completion of the
MidAmerican Merger in March, 1999. For additional information on
MidAmerican Energy, see its Annual Report on Form 10-K for the
year ended December 31, 1998, File No. 1-11505. The Company has
achieved significant growth in earnings and assets over the past
five years through: (i) acquisitions that complement and
diversify the Company's existing business, broaden the geographic
locations of and fuel sources used by its projects and enhance
its competitive capabilities; (ii) enhancement of the financial
and technical performance of existing and acquired projects; and
(iii) development and construction of new plants and facilities
("greenfield development"). The Company's Senior unsecured
obligations have received investment grade ratings of Baa3, BBB-
and BBB- from Moody's Investor Services Inc. ("Moody's"),
Standard & Poors Ratings Services (S&P) and Duff & Phelps Credit
Rating Company (DCR). The Company's utility subsidiaries are
also investment grade rated by Moody's, S&P and DCR: MidAmerican
Energy (A3, A- and A+) and Northern (A3, A- and A).

The market capitalization of the Company has risen at a
compound annual rate of 33% from approximately $498 million in
December 1994 to approximately $1.644 billion in March 1999, the
revenues of the Company have risen at a compound annual rate of
95% from approximately $186 million in 1994 to approximately $2.7
billion in 1998 and net income available to common stockholders
excluding extraordinary item and the cumulative effect of a
change in accounting principle has risen at a compound annual
rate of 42% from approximately $34 million in 1994 to
approximately $138 million in 1998. From 1994 through 1998, the
Company's EBITDA and total assets have increased by a compound
annual growth rate of 65% and 68%, respectively. EBITDA for the
year ended December 31, 1998 was $953 million. "EBITDA" means
the Company's earnings, before interest, taxes, depreciation and
amortization. Information concerning EBITDA is presented here
not as a measure of operating results, but rather as a measure of
the Company's ability to service debt. EBITDA should not be
construed as an alternative to either (i) operating income
(determined in accordance with Generally Accepted Accounting
Principles ("GAAP")) or (ii) cash flow from operating activities
(determined in accordance with GAAP). In this Annual Report,
references to "U.S. dollars," "dollars," "US $," "$" or "cents"
are to the currency of the United States and references to
"pounds sterling", "pounds," "sterling," "pence" or "p" are to
the currency of the United Kingdom.

The Company's Common Stock is traded on the New York
(trading symbol: MEC), Pacific and London Stock Exchanges. The
principal executive offices of the Company are located at 666
Grand Avenue, Des Moines, Iowa 50309 and its telephone number is
(515) 242-4300. The Company was initially incorporated in 1971
under the laws of the State of Delaware. The Company was
reincorporated in 1999 in Iowa in connection with the recent
MidAmerican Merger described below.

Recent Acquisitions
<PAGE>
Beginning in 1995, the Company has consummated several
significant acquisitions, which have been integrated and
immediately accretive to earnings. In January 1995, the Company
acquired Magma Power Company ("Magma"), a publicly-traded United
States independent power producer with 228 net MW of operating
capacity and 154 net MW of ownership capacity, for approximately
$958 million. The Magma acquisition, combined with the Company's
previously existing assets, made the Company at that time the
world's largest independent geothermal power producer (based on
the Company's estimate of aggregate MW of electric generating
capacity in operation and construction).

In April 1996, the Company completed the purchase for
approximately $70 million of its partner's interests in four
electric generating plants in Southern California, resulting in
sole ownership of the Imperial Valley Projects' 228 net MW of
aggregate operating capacity.

In August 1996, the Company acquired Falcon Seaboard
Resources, Inc. ("Falcon Seaboard") for approximately $226
million, thereby acquiring significant ownership in 520 net MW of
natural gas-fired electric production facilities located in New
York, Texas and Pennsylvania and a related gas transmission
pipeline.

In December 1996, the Company acquired a majority of the
common shares of Northern. Northern is one of the twelve regional
electricity companies (each, a "REC") which came into existence
as a result of the restructuring and subsequent privatization of
the electricity industry in the United Kingdom ("U.K.") in 1990.
Northern distributes electricity in its authorized area located
in northeast England which covers approximately 14,400 square
kilometers and has a population of approximately 3.2 million
people. Northern also supplies electricity and gas inside and
outside its authorized area and currently owns interests in four
producing gas field operations in the North Sea.

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

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

Strategy

The Company's growth strategy remains focused on taking
advantage of the investment opportunities created by the
continuing restructuring and privatization in energy sectors
throughout the world. In order to effectively execute its growth
strategy, the Company has organized its operations into a
functional structure. The functional alignment is believed to
allow for greater efficiencies in operations and better
coordination and asset utilization in developing the Company's
business.

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

* Growth through International and Domestic Acquisitions. The
Company has successfully completed six acquisitions in the past
four years, each of which was accretive to earnings. The Company
believes several of these acquisitions provided it with
specialized skills and experience that enhance its competitive
position in the areas it has targeted for future growth. For
example, the Company's acquisition of Northern, a U.K. regional
electricity company engaged in electricity distribution and
supply and gas supply and related businesses, was the first step
in its planned expansion into those sectors in the U.S. and
elsewhere throughout the world. In addition, since the U.K.
progressively deregulated its electricity and gas supply sectors,
the Company believes that its Northern management team has the
knowledge and skills to compete in a competitive supply market.
By virtue of its ownership of Northern, the Company also
possesses the sophisticated billing and proprietary information
systems that are believed by the Company to be critically
important components of the skill and technology base necessary
to compete effectively in a restructured environment. More
recently, the Company completed the acquisition of MidAmerican
Energy, a leading regional provider of energy and related
services in Iowa and three neighboring states.

The Company believes that the electricity industry
in the U.S. will also progressively restructure over the
next three to five years and will largely follow the
regulatory model established in the U.K. (with incentive
based rates or price caps). As currently regulated U.S.
electricity distributors and electricity and gas
suppliers attempt to rationalize their businesses to
maintain profitability in a price competitive market, the
Company believes that opportunities will become available
to low cost and reliable providers of energy services to
gain market share in energy supply and provide additional
services to competitors (such as utility line
construction and maintenance services, metering, customer
billing and information systems services). As a result,
the Company believes that by acquiring a U.S. utility
operation such as MidAmerican Energy and transferring the
knowledge, skills and systems gained at Northern, it can
create a platform from which a U.S. energy distribution
and supply business can be profitably established and
expanded in a competitive market.

* Growth through Greenfield Development of Energy Projects.
As part of the recent acquisition of MidAmerican, the Company has
commenced development of a 500 MW natural gas fired generation
facility which would sell power on a partial contract and partial
merchant basis. The facility is expected be located near the
Quad Cities in Illinois and Iowa on the border of two electric
reliability districts, the Mid-Continent Area Power Pool and the
Mid-America Interconnection Network. In addition, the Company
continues to view the international power generation sector as an
attractive market for the development of new greenfield energy
opportunities, an area in which it has demonstrated substantial
expertise. In the past four years, the Company has developed and
financed four new Philippine power projects, three of which are
now operating and the fourth of which is under construction and
<PAGE>
on schedule and within budget. With CalEnergy Gas UK, a wholly
owned subsidiary of Northern, the Company has expanded its
development strategy to include integrated generation and
upstream natural gas operations. The addition of gas exploration,
production and technical storage capabilities allows the Company
to expand its number of target markets throughout the world. In
addition, utilization of its geotechnical expertise in this
manner allows early entrance with limited upfront capital
expenditures into markets in which the Company might not
otherwise have power development opportunities. The integration
of power generation plants with the upstream gas sources in
competitive energy markets will also produce market arbitrage
opportunities to sell either gas or electricity depending upon
market conditions at the time. The Company continues to develop
two upstream gas projects, one in Western Australia at the Gingin
field in the Perth Basin and one in Poland at the large Pila
Concession.

* Profit Enhancement through Operating Efficiencies while
Maintaining Quality and Reliability of Service. The Company
aggressively pursues profitability improvements through
efficiency and productivity gains at existing operations. The
cost of production per kWh at the Imperial Valley Projects (as
defined herein) has declined from 5.3 cents/kWh in 1994 to 2.8
cents/kWh in 1998. The Company has achieved these efficiencies
while maintaining high reliability and safety in its operation.
Through continuing advancements in drilling technology, reservoir
modeling and well maintenance techniques, the production capacity
of new and existing wells has been improved or maintained and, as
a result, the useful output of the various geothermal resources
has been improved or maintained.

* Continued Diversification of Revenue Base and Fuel
Sources. The Company believes that following the MidAmerican
Merger it has a diversified revenue base, distributed among its
ownership of two operating electricity and gas utilities, its
ownership of interests in thirty-three projects with 10,000 net
MW in operation, under construction or in development and its
ownership of producing gas fields (all as described in more
detail below). In addition to the revenues of MidAmerican Energy
and Northern, which are largely derived from their electricity
distribution and electricity and gas supply activities, a
significant portion of the Company's revenues will be from its
50% equity ownership interest in CE Generation, the project
subsidiaries of which have long-term contracts with seven large
U.S. utility companies, and the Company's subsidiaries' long-term
contracts with the Government of the Philippines (sovereign
ratings of Ba1/BB+). The Company intends to seek continued
diversification of its revenue base and fuel sources through
acquisitions and greenfield development.

* Maintenance of Prudent Financial and Risk Management
Practices. The Company has consistently maintained, and intends
in the future to maintain what it believes to be prudent
financial and risk management practices. A primary objective of
the Company is to structure project financings for development
projects which can be rated investment grade by Moody's, DCR and
S&P. The Company's senior unsecured obligations are rated Baa3,
BBB- and BBB-. Its MidAmerican Energy subsidiary is rated A3, A+
and A-; Salton Sea Funding Corp. is rated Baa2/BBB; CE Generation
LLC is rated Baa3, BBB and BBB-; its Northern Electric subsidiary
is rated A3, A and A-, and its CE Electric UK Funding Company
subsidiary's senior notes are rated Baa1, A- and A-. The debt
ratings reflected above have been published by Moody's, DCR (for
all except Salton Sea Funding) and S&P, respectively, in respect
of certain senior indebtedness of the respective issuers shown.
These ratings may be changed from time to time by the ratings
agencies. The project financing structures utilized to date by
the Company include as a fundamental protection for the Company's
other assets the requirement that (with certain minimal
exceptions) the funds borrowed and other obligations for the
purpose of financing or operating a project are to be primarily
or entirely under loan agreements, project agreements and related
documents which provide that the obligations and loans are to be
performed or repaid solely by the project and from the project's
revenues and that the security granted to secure the loan and
other obligations be limited to the capital stock, assets,
contracts and cash flow of the project or the project holding
company. Under this type of structure, the lenders and other
project contracting parties cannot seek recourse against the
Company or its other subsidiaries or projects. The Company
intends to continue to structure future projects in a manner
which minimizes the exposure of the Company's other assets
through appropriate non-recourse project structures.
<PAGE>
* Continued Adherence to Strict Project Evaluation
Criteria. The Company intends to operate only in those countries
where economic fundamentals are believed to be attractive and
risks can be contractually mitigated or adequately covered by
insurance. The Company's international investment criteria
generally includes giving due consideration, where appropriate,
to the following:
/ Sovereign guarantees;
/ Significant demand for new power generating
facilities;
/ An established legal system providing for
enforceability of contracts and regulations;
/ "Take or Pay" contracts with utilities, governments
or other parties with acceptable creditworthiness
which provide for primarily US$-denominated payments
and certain contractual protections regarding
currency convertibility and transferability;
/ Fixed-price date-certain, turnkey construction
contracts with liquidated damages and performance
security provisions; and
/ Availability of political risk insurance.

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

The Global Energy Market

The opportunity for independent power generation and energy
distribution and supply has expanded from a United States market
to a global competitive market as many foreign countries have
initiated restructuring and privatization policies that encourage
the development of independent power generation and independent
distribution and supply of energy. Internationally, large amounts
of new electric power generating capacity are required in
developing countries. The movement toward privatization in some
developing countries has created significant new markets outside
the United States. The need for rapid economic expansion has
caused many countries to select private power development as
their only practical alternative and to restructure their
legislative and regulatory systems to facilitate such
development. The Company believes that the significant need for
power in developing markets has created strong local support for
private power projects in many foreign countries and has
increased the availability of attractive long-term power
contracts. The Company intends to take advantage of opportunities
in these markets and to develop, construct and acquire power
generation, distribution and supply and related energy projects
meeting its strategic criteria outside the United States.

In addition, as privatization, deregulation and
restructuring initiatives are enacted in various countries and
states, the Company has identified a number of promising
opportunities to acquire power generation, distribution and
supply assets, as well as other energy related infrastructure
assets. These opportunities include bidding opportunities in
connection with privatization initiatives in the electricity and
gas distribution and supply sectors in various regions and
countries, including principally Europe, South America, Australia
and New Zealand. The Company expects to see more of such
acquisition opportunities in additional markets in the future.

In pursuing its strategy, the Company presently intends to
focus upon development and acquisition opportunities in countries
possessing characteristics which meet the Company's general
investment criteria. At the present time, the Company is active
in the United States, the Philippines and the United Kingdom and
is pursuing development opportunities in Australia, Canada,
Europe, New Zealand and South America. Set forth below is certain
general information concerning the present status of the energy
markets in those countries in which the Company currently has
significant operations.

The United States
<PAGE>
In the United States, the independent power industry
expanded rapidly in the 1980s, facilitated by the enactment of
the Public Utilities Regulatory Policies Act ("PURPA"). PURPA was
enacted to encourage the production of electricity by non-utility
companies (frequently referred to as independent power companies)
as well as to lessen reliance on imported fuels. According to the
Utility Data Institute, independent power producers were
responsible for the installation of approximately 30,000 MW of
capacity, or 50%, of the United States electric generation
capacity that has been placed in service since 1988. However, as
the size of the United States independent power market increased,
available domestic power capacity and competition in the industry
also significantly increased and the need for new generating
capacity has been reduced.

During the last few years, many states began to accelerate
the movement toward more competition in many aspects of the
electric power market, including generation, transmission,
distribution and supply. Extensive federal and state legislative
and regulatory reviews are presently underway in an effort to
further such competition. In particular, the state of California
has adopted a bill to restructure the electric industry by
providing for a phased-in competitive power generation industry,
with a power exchange and independent system operator, and for
direct access to generation for all power purchasers outside the
power exchange under certain circumstances. The bill provides
that existing qualifying facility power sales agreements will be
honored. Other states have or are expected to take similar steps
aimed at increasing competition by restructuring the electric
industry, allowing retail competition and deregulating most
electric rates. In addition, recent federal legislation has been
proposed which would repeal PURPA and the Public Utility Holding
Company Act of 1935, as amended, respectively. The Company cannot
predict the final form or timing of the proposed industry
restructuring or the impact on its operations. However, the
Company believes that the impending changes in the regulation of
the United States power markets will reflect many aspects of the
United Kingdom model (discussed below) for competitive
generation, transmission, distribution and supply of energy. The
Company further expects that the current effort to introduce
broader wholesale and retail competition in the United States
will result in a continuation and acceleration of the recent
trend toward consolidation among domestic utilities and
independent power producers and an increase in the trend toward
disaggregation (or unbundling) of vertically integrated utilities
into separate generation, transmission and distribution
businesses.

MidAmerican Energy is subject to comprehensive regulation by
several utility regulatory agencies which significantly
influences the operating environment and the recoverability of
costs from utility customers. That regulatory environment has to
date, in general, given MidAmerican Energy an exclusive right to
serve electricity customers within its service territory and, in
turn, the obligation to provide electric service to those
customers.

In Illinois, the electric retail business is opening up to
competition and will be phased in between October 1999 and May
2002.

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

Prior to July 11, 1997, MidAmerican Energy recouped its fuel
costs for electricity generation from its Iowa customers on a
current basis through the Iowa energy adjustment clause, and
thus, fuel costs had little impact on net income. Since then,
base rates for Iowa customers include a factor for recovery of a
representative level of fuel costs. However, to the extent actual
fuel costs vary from that factor within a defined range, earnings
are impacted.

MidAmerican Energy provides gas service at retail pursuant
to non-exclusive municipal franchises. The cost of gas is
recovered from customers through a Purchased Fuel Adjustment
Clause.
<PAGE>
In connection with the recent approval by the Iowa Utilities
Board of the MidAmerican Merger, MidAmerican Energy agreed, among
other things, to use all commercially reasonable efforts to
maintain an investment grade credit rating for MidAmerican Energy
and its long-term debt and to seek the approval of the Iowa
Utilities Board of a reasonable utility capital structure if
MidAmerican Energy's common equity level decreases below
specified levels (42% and 39%, respectively, of total
capitalization) under certain circumstances.

Statement of Financial Accounting Standards (SFAS) No. 71
sets forth accounting principles for operations that are
regulated and meet certain criteria. For operations that meet
the criteria, SFAS 71 allows, among other things, the deferral of
costs that would otherwise be expensed when incurred. A possible
consequence of the changes in the utility industry is the
discontinued applicability of SFAS 71. The majority of
MidAmerican Energy's electric and gas utility operations
currently meet the criteria of SFAS 71, but its applicability is
periodically reexamined. If utility operations no longer meet
the criteria of SFAS 71, MidAmerican Energy would be required to
write off the related regulatory assets and liabilities from its
balance sheet and thus, a material adjustment to earnings in that
period could result.

The United Kingdom

The electricity industry in the United Kingdom has seen the
privatization of electric supply and distribution, and gradual
phase-in of competition in supply, since 1990. The Electricity
Act of 1989 established an industry structure that permitted this
phased-in competition to occur. Since that time, in England and
Wales, electricity is produced by generators, the largest of
which are National Power, PowerGen and British Energy.
Electricity is transmitted through the national grid transmission
system by The National Grid Company plc ("NGC") and distributed
to customers by the twelve regional electric companies ("RECs")
in their respective authorized areas. Most customers currently
are supplied with electricity by their local REC, although there
are other suppliers holding second tier supply licenses,
including other generators and RECs, who can compete to supply
customers in that REC's authorized area. During the fourth
quarter of 1998, the market for supplying electricity began to be
opened to competition, and all customers are expected to
eventually be free to choose their electricity supplier. This
phased-in program, which is proceeding by geographic areas, is
expected to be completed by the summer of 1999.

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

Distribution. Each of the RECs is required to offer terms
for connection to its distribution system to any person, and for
use of its distribution system to any authorized electricity
operator, in each case located in its franchise area. In
providing use of its distribution system, a REC must not
discriminate between its own supply business and that of any
other authorized electricity operator, or between those of other
authorized electricity operators; nor may its charges differ
except where justified by differences in cost.

Most revenue of the distribution business is controlled by a
distribution price control formula. The Retail Price Index
("RPI") used in this formula reflects the average of the 12 month
inflation rates recorded for each month in the previous July to
December period. The distribution price control formula also
reflects an XD factor which was established by the Regulator
following review and is set at 3% from April 1, 1997. This
formula determines the maximum average price per unit of
electricity distributed (in pence per kilowatt hour) which a REC
is entitled to charge. The distribution price control formula
permits RECs to receive additional revenues due to increased
distribution of units and a predetermined increase in customer
numbers. The price control does not seek to constrain the profits
of a REC from year to year. It is a control on income which
operates independently of the REC's costs. During the lifetime of
the price control additional cost savings therefore contribute
<PAGE>
directly to profit. The distribution prices allowable under the
current distribution price control formula are expected to be
reviewed by the Regulator at the expiration of the formula's
scheduled five-year duration, effective as of April 1, 2000. The
formula may be further reviewed at other times in the discretion
of the Regulator.

With effect from April 1, 1998, domestic and smaller
commercial customers' prices became subject to a price cap which
required reductions of 4.2% (less inflation) compared to the
prices prevailing at August 1, 1997. A further reduction of 3%
(less inflation) will be required on April 1, 1999.

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

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

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

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

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

Northern's supply business generally involves entering into
fixed price contracts to supply electricity to its customers.
Northern obtains the electricity to satisfy its obligations under
such contracts primarily by purchases from the Pool. Because the
price of electricity purchased from the Pool, Northern is exposed
to risk arising from differences between the fixed price at which
it sells and the fluctuating prices at which it purchases
electricity, unless it can effectively hedge such exposure. In
addition, the United Kingdom government has announced plans to
reform the wholesale trading market for electricity by
eliminating the Pool and creating a bilateral wholesale trading
market. The announced date for elimination of the Pool is April,
2000. Elimination of the Pool will create risks of a mismatch
between the prices at which Northern purchases electricity from
wholesale suppliers and the price at which it has, or will,
<PAGE>
contract to sell electricity to its customers. Northern's
ability to manage such risks at acceptable levels will depend, in
part, on the specifics of the supply contracts that Northern
enters into, Northern's ability to implement and manage an
appropriate contracting and hedging strategy, and the development
of an adequate market for hedging instruments.

The Company's Distribution and Supply Business

MidAmerican Energy Company

MidAmerican Energy is the largest energy company
headquartered in Iowa, with assets and operating revenues for the
year ended December 31, 1998 totaling $3.6 billion and $1.7
billion, respectively. Its strategy is to become the leading
regional provider of energy and complementary services.
MidAmerican is primarily engaged in the business of generating,
transmitting, distributing and selling electric energy and in
distributing, selling and transporting natural gas. MidAmerican
distributes electric energy at retail in Council Bluffs, Des
Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa, the
Quad Cities (Davenport and Bettendorf, Iowa and Rock Island,
Moline and East Moline, Illinois) and a number of adjacent
communities and areas. It also distributes natural gas at retail
in Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City
and Waterloo, Iowa; the Quad Cities; Sioux Falls, South Dakota;
and a number of adjacent communities and areas. As of December
31, 1998, MidAmerican had 652,900 retail electric customers and
621,500 retail natural gas customers.

In addition to retail sales, MidAmerican Energy delivers
electricity to other utilities and municipalities who distribute
it to end-use customers (sales for resale) and MidAmerican Energy
transports natural gas, for a fee, through its distribution
system for certain large customers who have independently secured
their own supply of natural gas.

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

MidAmerican Energy has a residential, agricultural,
commercial and diversified industrial customer group, in which no
single industry or customer accounted for more than 3% (food and
kindred products industry) of its total 1998 electric operating
revenues or 3% (food and kindred products industry) of its total
1998 gas operating margin. Among the primary industries served by
MidAmerican Energy are those which are concerned with the
manufacturing, processing and fabrication of primary metals, real
estate, food products, farm and other non-electrical machinery,
and cement and gypsum products.

During 1998, MidAmerican Energy increased its emphasis on
wholesale gas trading and marketing activity, some of which was
previously managed by one of MidAmerican's nonregulated
subsidiaries.

For the year ended December 31, 1998, MidAmerican derived
approximately 69% of its gross operating revenues from its
regulated electric business, and 25% from its regulated gas
business and 6% from its nonregulated business activities. For
1997 and 1996, the corresponding percentages were 65% electric
and 31% gas and 4% nonregulated; and 66% electric and 32% gas and
2% nonregulated, respectively.

The electric utility industry is in the midst of significant
regulatory change. Traditionally, prices charged by electric
utility companies have been regulated by federal and state
commissions and have been based on cost of service. In recent
years, changes have occurred, and are expected to continue to
occur, that move the electric utility industry toward a more
competitive, market-based pricing environment. These changes
will have a significant impact on the way MidAmerican Energy does
business.

A substantial majority of MidAmerican's business still
operates in a rate-regulated environment and, accordingly, many
decisions for obtaining and using resources are evaluated from an
electric and gas regulated business perspective. However,
beginning January 1, 1998, MidAmerican Energy also manages its
<PAGE>
operations as four distinct business units: generation,
transmission, energy distribution and retail. With these four
business units, MidAmerican Energy is able to focus on the
specific needs and anticipated risks and opportunities of its
major businesses. Certain administrative functions are handled
by a corporate services group which supports all of the business
units.

Although specific functions may be changed as future
circumstances warrant, the focus of each business unit has been
established. Presently, significant functions of the generation
business unit include the production of electricity, the purchase
of electricity and natural gas, and the sale of wholesale
electricity and natural gas. The transmission business unit
coordinates all activities related to MidAmerican Energy's
electric transmission facilities, including monitoring access to
and assuring the reliability of the transmission system. The
energy distribution business unit distributes electricity and
natural gas to end-users and conducts related activities. Retail
includes marketing, customer service and related functions for
core and complementary products and services.

Total Electric Sales of MidAmerican Energy By Customer Class

1998 1997 1996

Residential 22.2% 20.9% 21.1%
Small General Service 17.5 16.5 16.2
Large General Service 28.1 27.4 27.6
Other 4.4 4.4 4.5
Sales for Resale 27.8 30.8 30.6
_____ _____ _____
Total 100.0% 100.0% 100.0%

Retail Electric Sales of MidAmerican Energy By State

1998 1997 1996

Iowa 88.4% 88.6% 88.7%
Illinois 10.9 10.7 10.6
South Dakota 0.7 0.7 0.7
____ _____ _____
Total 100.0%100.0% 100.0%

In an Iowa pricing settlement approved in 1997 by the Iowa
Utilities Board, MidAmerican Energy was given permission to
negotiate individual contracts with its industrial and commercial
electric customers. The negotiated contracts have differing terms
and conditions as well as prices. The contracts range in length
from five to ten years, and some have price renegotiation and
early termination provisions exercisable by either party. A vast
majority of the contracts are for terms of seven years or less,
although some large customers have agreed to 10-year contracts.
Prices are set as fixed prices; however, many contracts allow for
potential price adjustments with respect to environmental costs,
government imposed public purpose programs, tax changes, and
transition costs. While the contract prices are fixed (except for
the potential adjustment elements), the costs MidAmerican Energy
<PAGE>
incurs to fulfill these contracts will vary. MidAmerican Energy
presently intends to manage this risk through hedging and other
similar arrangements. On an aggregate basis, the annual revenues
under these contracts are approximately $155 million.

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

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

Historical gas sales, excluding transportation throughput,
by customer class as a percent of total gas sales and by state as
a percent of total retail gas sales are shown below:

Total Gas Sales of MidAmerican Energy By Customer Class

1998 1997 1996

Residential 59.9% 60.8% 61.1%
Small General Service 32.1 33.1 33.3
Large General Service 3.7 4.2 4.6
Sales for Resale and Other 4.3 1.9 1.0
______ ______ ______
Total 100.0% 100.0% 100.0%

Retail Gas Sales of MidAmerican Energy By State

1998 1997 1996

Iowa 79.0% 79.1% 78.0%
Illinois 10.2 10.4 11.0
South Dakota 10.1 9.8 10.3
Nebraska 0.7 0.7 0.7
______ ______ ______
Total 100.0% 100.0% 100.0%

There are seasonal variations in MidAmerican Energy's
electric and gas businesses which are principally related to the
use of energy for air conditioning and heating. In 1998, 40% of
MidAmerican Energy's electric revenues were reported in the
months of June, July, August and September, reflecting the use of
electricity for cooling, and 54% of MidAmerican Energy's gas
revenues were reported in the months of January, February, March
and December, reflecting the use of gas for heating.

The annual hourly peak demand on MidAmerican Energy's
electric system occurs principally as a result of air
conditioning use during the cooling season. In July 1998,
<PAGE>
MidAmerican Energy recorded an hourly peak demand of 3,643 MW,
which is 90 MW more than MidAmerican Energy's previous record
hourly peak of 3,553 MW set in 1995.

MidAmerican Energy's accredited net generating capability in
the summer of 1998 was 4,425 MW. Accredited net generating
capability represents the amount of generation available to meet
the requirements on MidAmerican Energy's energy system, net of
the effect of participation purchases and sales and consists of
Company-owned generation and power purchased under a long-term
power purchase contract. The net generating capability at any
time may be less due to regulatory restrictions, fuel
restrictions and generating units being temporarily out of
service for inspection, maintenance, refueling or modifications.

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

Each MAPP participant is required to maintain for emergency
purposes a net generating capability reserve of at least 15%
above its system peak demand. If a participant's capability
reserve falls below the 15% minimum, significant penalties could
be contractually imposed by MAPP. MidAmerican Energy's reserve
margin for 1998 was approximately 20%.

In an effort that began in 1996, MidAmerican is continuing
to redeploy investments and to invest in other lines of business
that support its strategy. For example, MidAmerican Realty
Services, with over 4,500 independent sales representatives and
approximately 1,150 employees, offers integrated real estate
services in seven states including residential brokerage,
relocation, title, abstract and mortgage services. On a
consolidated basis, the real estate brokerage operations are the
second largest in the nation, and the Company believes these
operations will provide a strategically important customer access
point and an advertising and "branding" vehicle as energy markets
deregulate, in addition to being profitable businesses on a
stand-alone basis.

Northern Electric

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

At December 31, 1998, Northern's electricity distribution
network (excluding service connections to consumers) included
approximately 17,000 kilometers of overhead lines and
approximately 26,000 kilometers of underground cables.
Substantially all substations are owned in freehold, and most of
the balance are held on leases which will not expire within 10
years. In addition to the circuits referred to above, Northern's
distribution facilities also include approximately 24,000
transformers and approximately 24,000 substations.

Northern Electric Supply Limited ("Northern Supply") focuses
on Northern's supply business and is responsible for marketing,
tariff setting, contracts and customer service in connection with
the supply of both electricity and gas. Northern's supply
business involves the bulk purchase of electricity, primarily
from the Pool, and subsequent sale to individual customers.
<PAGE>
Under the terms of its public electricity supply ("PES") or
"first tier" license, Northern currently holds the right to
supply approximately 1.5 million supply customers within
Northern's authorized area. In addition to competing for supply
customers in its authorized area, Northern holds a second tier
license to compete with the RECs and other suppliers to provide
electricity to supply customers outside its authorized area.
Northern is one of the largest suppliers in the competitive and
open electricity market in the United Kingdom and supplies
customers in all 15 PES areas in Great Britain and Northern
Ireland.

Northern Supply also competes to supply gas inside and
outside its authorized area. Over the last six months of 1998,
Northern expanded its supply customer base by 20% by attracting
nearly 300,000 new gas customers in part through the Dual Fuel
marketing program.

Northern Utility Services Limited ("Northern Utility") is an
engineering company whose role is to adapt, maintain and restore
the distribution network of Northern and to sell related services
to third parties. Northern Utility has been able to make
significant cost reductions for Northern during the past year by
working with suppliers in order to improve core processes, close
selected depot locations, increase staff productivity and reduce
material and plant costs. Northern Utility has pioneered
techniques using innovative diagnostic testing equipment which
reduces the need for intrusive maintenance. The equipment can
identify some of the causes of potential systems failures before
breakdown and subsequent loss of supply occurs. Also, the
continued development in the use of trenchless technology has
brought both financial and environmental benefits to Northern and
its customers. While Northern Utility's largest customer is
Northern Distribution, it currently sells an average of
approximately 14% of its services to third parties. Northern
Utility is Northern's largest employer.

Northern Electric Retail Limited ("Northern Retail"), a
subsidiary of Northern, sells electrical and gas appliances and
provides account collection and customer services for Northern's
other businesses.

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

The Company's Power Generation Project Portfolio

Following the MidAmerican Merger in March 1999, the Company
has ownership interests in generating facilities with an
aggregate of (i) 9,517 net MW in projects in operation
representing an aggregate net capacity owned of 5,197 net MW of
electric generating capacity, (ii) 209 net MW in three projects
under construction representing an aggregate net capacity of 135
net MW of electric generating capacity and (iii) 594 net MW in
three projects in advanced development stages with signed power
sales agreements or under award representing an aggregate net
capacity owned of 569 net MW of electric generating capacity.

The following tables set out certain information concerning
various Company projects in operation, under construction and in
development pursuant to signed power sales agreements or awarded
mandates.
<PAGE>
<TABLE>
<CAPTION>
Project1,2 Facility Net MW Fuel Location Commercial U.S. $ Power Political
Net MW Owned3 Operation Payments Purchaser4 Risk
<S> <C> <C> <C> <C> <C> <C> <C> <C> Insurance
Projects in
Operation
Council Bluffs
Energy Center
units 1 & 2 131 131 Coal Iowa 1954,1958 Yes MEC No
Council Bluffs
Energy Center
units 3 675 534 Coal Iowa 1978 Yes MEC No
Louisa Generation
Station 700 616 Coal Iowa 1983 Yes MEC No
Neal Generation
Station units
1 & 2 435 435 Coal Iowa 1964,1972 Yes MEC No
Neal Generation
Station unit 3 515 371 Coal Iowa 1975 Yes MEC No
Neal Generation
Station unit 4 624 253 Coal Iowa 1979 Yes MEC No
Ottumwa Generation
Station 716 372 Coal Iowa 1981 Yes MEC No
Quad-Cities
Power Station 1,529 383 Nuclear Illinois 1972 Yes MEC No
Riverside
Generation
Station 135 135 Coal Iowa 1925-61 Yes MEC No
Combustion
Turbins 758 758 Gas Iowa 1969-95 Yes MEC No
Moline Water
Power 3 3 Hydro Illinois 1970 Yes MEC No
Imperial Valley 268 134 Geo Calif. 1986-96 Yes Edison No
Saranac 240 90 Gas N.Y. 1994 Yes NYSEG No
Power Resources 200 100 Gas Texas 1988 Yes TUEC No
NorCon 80 32 Gas Penn. 1992 Yes NIMO No
Yuma 50 25 Gas Arizona 1994 Yes SDG&E No
Roosevelt Hot
Springs 23 17 Geo Utah 1984 Yes UP&L No
Desert Peak 10 10 Geo Nevada 1985 Yes N/A No
Mahanagdong 165 149 Geo Philippine 1997 Yes PNOC-EDC Yes
EDC GOP
Malitbog 216 216 Geo Philippine 1996-97 Yes PNOC-EDC Yes
GOP
Upper Mahiao 119 119 Geo Philippine 1996 Yes PNOC-EDC Yes
GOP
Teesside
Power Ltd. 1,875 289 Gas England 1993 No Various No
Viking 50 25 Gas England 1998 No Northern No
Total Projects
in Operation 9,517 5,197

Projects Under
Construction

Casecnan 150 105 Hydro Philippine 2000 Yes NIA (GOP) Yes
Salton Sea V 49 25 Geo Calif. 2000 Yes Zinc/TBD No
CE Turbo 10 5 Geo Calif. 2000 Yes Zinc/TBD No

Total Projects
Under
Construction 209 135

Development
Projects 5

Telephone Flat 44 44 Geo Calif. 2001 Yes BPA No
Cordova Merchant
Plant 500 500 Gas Illinois 2001 Yes TBD No
Exeter Power Ltd. 50 25 Gas England 2000 No Northern No

Total Development
Projects 594 569

Total Power
Generation
Projects 10,320 5,901
</TABLE>
1 The Company operates all such projects other than Teesside Power Limited,
Quad Cities Power Station, Ottumwa Generation Station and Desert Peak.

2 The above table excludes three projects in Indonesia, two of which are
currently in arbitration. One unit became operational in March 1998.

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

4 PNOC-Energy Development Corporation ("PNOC-EDC"); Government of the
Philippines ("GOP") and Philippine National Irrigation Administration ("NIA")
(NIA also purchases water from this facility), Northern Electric plc
("Northern"). The Government of the Philippines undertaking supports PNOC-EDC's
and NIA's respective obligations. Southern California Edison Company
("Edison"); San Diego Gas & Electric Company ("SDG&E"); Utah Power & Light
Company ("UP&L"); Bonneville Power Administration ("BPA"); New York State
Electric & Gas Corporation ("NYSEG"); Texas Utilities Electric Company ("TUEC");
Niagara Mohawk Power Corporation ("NIMO"); and MidAmerican Energy Company
("MEC").

5 Significant contingencies exist in respect of awards, including without
limitation, the need to obtain financing, permits and licenses, and the
completion of construction. The company is also pursuing a number of other
power projects which are in the preliminary stage of development.

<PAGE>
PROJECTS IN OPERATION

United States Power Generation

MidAmerican Energy Generation Facilities

All of the coal-fired generating stations operated by
MidAmerican Energy are fueled primarily by low-sulfur, western
coal from the Powder River Basin. The use of low-sulfur western
coal enables MidAmerican Energy to comply with the acid rain
provisions of the CAAA without having to install additional
costly emissions control equipment at its generating stations.
MidAmerican Energy's coal supply portfolio includes multiple
suppliers and mines under agreements of varying term and quantity
flexibility. During 1998 approximately 65% of MidAmerican
Energy's coal purchases were made under spot coal purchase
agreements. MidAmerican Energy regularly monitors the western
coal market, looking for opportunities to improve its coal supply
portfolio. MidAmerican Energy believes its sources of coal
supply are and will continue to be satisfactory.

MidAmerican Energy uses both the Union Pacific Railroad
("UP") and the Burlington Northern and Santa Fe Railway ("BNSF")
as originating carriers of its coal supply in order to achieve
transportation diversity and competitive rates. Coal is
delivered directly to MidAmerican Energy's Neal Energy Center and
Council Bluffs Energy Center ("CBEC") by the UP and the BNSF,
respectively. Coal for MidAmerican Energy's Louisa and Riverside
Energy Centers is delivered to an interchange point by the BNSF
for transportation to its destination by the I&M Rail Link.
Competitive rail access is available to CBEC and to the
interchange point for deliveries to Louisa and Riverside Energy
Centers. MidAmerican Energy believes its coal transportation
arrangements are adequate to meet its coal delivery needs.

MidAmerican Energy uses natural gas and oil as fuel for peak
demand electric generation, transmission support and standby
purposes. These sources are presently in adequate supply and
available to meet MidAmerican Energy's needs.

While coal deliveries to certain of MidAmerican Energy's
generating stations were adversely affected by the UP's
nationwide operational problems in 1997 and early 1998,
MidAmerican Energy believes its coal inventories are adequate to
meet its needs at expected generation levels.

MidAmerican Energy is a 25% joint owner of Quad Cities
Station. MidAmerican Energy has been advised by ComEd, the joint
owner and operator of Quad Cities Station, that the majority of
its uranium concentrate and uranium conversion requirements for
Quad Cities Station for 1999 can be met under existing supplies
or commitments. ComEd foresees no problem in obtaining the
remaining requirements now or obtaining future requirements.
ComEd further advises that all enrichment requirements have been
contracted through 2004. Commitments for fuel fabrication have
been obtained at least through 2001. ComEd does not anticipate
that it will have difficulty in contracting for uranium
concentrates for conversion, enrichment or fabrication of nuclear
fuel needed to operate Quad Cities Station.

CE Generation Geothermal Facilities

CE Generation affiliates currently operate eight geothermal
plants in the Imperial Valley in California (the "Imperial Valley
Project"). Four of these Imperial Valley Project plants (the
"Partnership Projects") were developed by Magma which originally
owned a 50% interest. On April 17, 1996, the Company completed
the Partnership Interest Acquisition pursuant to which the
Company acquired the remaining 50% interests in each of the
Partnership Projects for $70 million. The Partnership Projects
consist of the Vulcan, Hoch (Del Ranch), Elmore and Leathers
projects (the "Vulcan Project," the "Hoch (Del Ranch) Project,"
the "Elmore Project" and the "Leathers Project," respectively).
<PAGE>
The remaining four operating Imperial Valley Project plants
(the "Salton Sea Projects") are wholly owned by subsidiaries of
Magma. Three of these plants were purchased by Magma on March
31, 1993 from Union Oil Company of California. These geothermal
power plants consist of the Salton Sea I project (the "Salton Sea
I Project"), the Salton Sea II project (the "Salton Sea II
Project") and the Salton Sea III project (the "Salton Sea III
Project"). The fourth plant, the Salton Sea IV project (the
"Salton Sea IV Project"), commenced commercial operations in
1996.

Vulcan. The Vulcan Project sells electricity to Edison
under a 30-year SO4 Agreement that commenced on February 10,
1986. The Vulcan Project has a contract capacity and contract
nameplate of 29.5 MW and 34 MW, respectively. Under the SO4
Agreement, Edison is obligated to pay the Vulcan Project a
capacity payment, a capacity bonus payment and an energy payment.
The price for contract capacity payments is fixed for the life of
such SO4 Agreement. The as-available capacity price is based on
a payment schedule as approved by the CPUC from time to time.
The contract energy payment increased each year for the first ten
years, which period expired on February 9, 1996. Thereafter, the
energy payments are based on Edison's Avoided Cost of Energy.

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

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

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

Salton Sea I Project. The Salton Sea I Project sells
electricity to Edison pursuant to a 30-year negotiated power
purchase agreement, as amended (the "Salton Sea I PPA"), which
provides capacity and energy payments. The contract capacity and
contract nameplate are each 10 MW. The capacity payment is based
on the firm capacity price which is currently $132.58kW-year.
The contract capacity payment adjusts quarterly based on a basket
of energy indices for the term of the Salton Sea I PPA. The
energy payment is calculated using a Base Price (defined as the
initial value of the energy payment (4.701 cents per kWh for the
second quarter of 1992)), which is subject to quarterly
adjustments based on a basket of indices. The time period
weighted average energy payment for Salton Sea I was 5.4 cents
per kWh during 1998. As the Salton Sea I PPA is not an SO4
Agreement, the energy payments do not revert to Edison's Avoided
Cost of Energy.

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

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

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

CE Generation Gas Facilities

Yuma Project. The Yuma Project is a 50 net MW natural gas-
fired cogeneration project in Yuma, Arizona providing 50 MW of
electricity to San Diego Gas & Electric Company ("SDG&E") under
an existing 30-year power purchase contract. The energy is sold
at SDG&E's Avoided Cost of Energy and the capacity is sold to
SDG&E at a fixed price for the life of the power purchase
contract. The power is wheeled to SDG&E over transmission lines
constructed and owned by Arizona Public Service Company ("APS").
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. Since the
industrial entity has the right under its agreement to terminate
the agreement upon one year's notice if a change in its
technology eliminates its need for steam, and in any case to
terminate the agreement at any time upon three years notice,
there can be no assurance that the Yuma Project will maintain its
status as a QF. However, if the industrial entity terminates the
agreement, the Company anticipates that it will be able to locate
an alternative thermal host in order to maintain its status as a
QF. A natural gas supply and transportation agreement has been
executed with Southwest Gas Corporation, terminable under certain
circumstances by the Company and Southwest Gas Corporation. The
Yuma Project is unleveraged. The Company and SDG&E are currently
engaged in discussions regarding a potential contract amendment
of the Yuma PPA.

Saranac Project. Saranac is a 240 net MW natural gas-fired
cogeneration facility located in Plattsburgh, New York, which
began commercial operation in June 1994. Saranac has entered
into a 15-year power purchase agreement (the "Saranac PPA") with
NYSEG. Saranac is a QF and has entered into 15-year steam
purchase agreements (the "Saranac Steam Purchase Agreements")
with Georgia-Pacific Corporation and Tenneco Packaging, Inc.
Saranac has a 15-year natural gas supply contract (the "Saranac
Gas Supply Agreement") with Shell Canada Limited ("Shell Canada")
to supply 100% of Saranac's fuel requirements. Shell Canada is
responsible for production and delivery of natural gas to the
U.S.-Canadian border; the gas is then transported by the North
Country Gas Pipeline Corporation ("NCGP") the remaining 22 miles
to the plant. NCGP is a wholly-owned subsidiary of Saranac Power
Partners, L.P. (the "Saranac Partnership"), which also owns
Saranac. NCGP also transports gas for NYSEG and Georgia-Pacific.
Each of the Saranac PPA, the Saranac Steam Purchase Agreements
and the Saranac Gas Supply Agreement contains rates that are
fixed for the respective contract terms. Revenues escalate at a
higher rate than fuel costs. The Saranac Partnership is
indirectly owned by subsidiaries of CE Generation, Tomen
Corporation ("Tomen") and General Electric Capital Corporation.
<PAGE>
On February 14, 1995, NYSEG filed with the FERC a Petition
for a Declaratory Order, Complaint, and Request for Modification
of Rates in Power Purchase Agreements Imposed Pursuant to the
Public Utility Regulatory Policies Act of 1978 ("Petition")
seeking FERC (i) to declare that the rates NYSEG pays under the
Saranac PPA, which was approved by the New York Public Service
Commission (the "PSC"), were in excess of the level permitted
under PURPA and (ii) to authorize the PSC to reform the Saranac
PPA. On March 14, 1995, the Saranac Partnership intervened in
opposition to the Petition asserting, inter alia, that the
Saranac PPA fully complied with PURPA, that NYSEG's action was
untimely and that the FERC lacked authority to modify the Saranac
PPA. On March 15, 1995, the Company intervened also in
opposition to the Petition and asserted similar arguments. On
April 12, 1995, the FERC by a unanimous (5-0) decision issued an
order denying the various forms of relief requested by NYSEG and
finding that the rates required under the Saranac PPA were
consistent with PURPA and the FERC's regulations. On May 11,
1995, NYSEG requested rehearing of the order and, by order issued
July 19, 1995, the FERC unanimously (5-0) denied NYSEG's request.
On June 14, 1995, NYSEG petitioned the United States Court of
Appeals for the District of Columbia Circuit (the "Court of
Appeals") for review of FERC's April 12, 1995 order. FERC moved
to dismiss NYSEG's petition for review on July 28, 1995. On
October 30, 1996, all parties filed final briefs and the Court of
Appeals heard oral arguments on December 2, 1996. On July 11,
1997, the Court of Appeals dismissed NYSEG's appeal from FERC's
denial of the petition on jurisdictional grounds.

On August 7, 1997, NYSEG filed a complaint in the U.S.
District Court for the Northern District of New York against the
FERC, the PSC (and the Chairman, Deputy Chairman and the
Commissioners of the PSC as individuals in their official
capacity), the Saranac Partnership and Lockport Energy
Associates, L.P. ("Lockport") concerning the power purchase
agreements that NYSEG entered into with Saranac Partners and
Lockport. NYSEG's suit asserts that the PSC and the FERC
improperly implemented PURPA in authorizing the pricing terms
that NYSEG, the Saranac Partnership and Lockport agreed to in
those contracts. The action raises similar legal arguments to
those rejected by the FERC in its April and July 1995 orders.
NYSEG in addition asks for retroactive reformation of the
contracts as of the date of commercial operation and seeks a
refund of $281 million from the Saranac Partnership. Saranac and
other parties have filed motions to dismiss and oral arguments on
those motions were heard on March 2, 1998 and again on March 3,
1999. Saranac believes that NYSEG's claims are without merit for
the same reasons described in the FERC's orders.

Power Resources Project. Power Resources is a 200 net MW
natural gas-fired cogeneration project located near Big Spring,
Texas, which has a 15-year power purchase agreement (the "Power
Resources PPA") with Texas Utilities Electric Company. Power
Resources began commercial operation in June 1988. Power
Resources is a QF and has entered into a 15-year steam purchase
agreement (the "Power Resources Steam Purchase Agreement") with
Fina Oil and Chemical Company ("Fina"), a subsidiary of Petrofina
S.A. of Belgium. Power Resources has entered into an agreement
(the "FSGC Gas Supply Agreement") with Falcon Seaboard Gas
Company ("FSGC") for Power Resources' fuel requirements through
December 2003. In June 1995, FSGC and Louis Dreyfus Natural Gas
Corp. ("Dreyfus") executed an eight-year natural gas supply
agreement (the "FSGC-Dreyfus Gas Supply Agreement"), with which
FSGC will fulfill its supply commitment to PRI from October 1995
to the end of the term of the Power Resources PPA. Each of the
Power Resources PPA, the Power Resources Steam Purchase Agreement
and the FSGC Gas Supply Agreement contains rates that are fixed
for the respective contract terms. Revenues escalate at a higher
rate than fuel costs.

NorCon Project. NorCon is an 80 net MW natural gas-fired
cogeneration facility located in North East, Pennsylvania which
began commercial operation in December 1992. NorCon has a 25-
year power purchase agreement (the "NorCon PPA") with Niagara
Mohawk Power Corporation ("NIMO"). NorCon is a QF and has
entered into a 20-year steam purchase agreement (the "NorCon
Thermal Energy Agreement") with Welch Foods Inc., a Cooperative
("Welch Foods"). NorCon has a 15-year natural gas supply
contract (the "NorCon Gas Purchase Agreement") with Louis Dreyfus
Gas Marketing Corp. to supply 100% of NorCon's fuel requirements.
A twenty-year natural gas transportation agreement has been
entered into with National Fuel Gas Supply Corporation ("National
<PAGE>
Fuel") to provide transportation to NorCon. Transportation costs
are deducted from payments made pursuant to the NorCon Gas
Purchase Agreement. The NorCon Thermal Energy Agreement contains
rates that escalate at an inflation-based index, and the NorCon
Gas Purchase Agreement's rates are fixed for the contract term.
NorCon Power Partners, L.P. ("the "NorCon Partnership"), which
owns NorCon, is indirectly owned by subsidiaries of CE Generation
and Tomen. The NorCon project has had a number of on-going
contractual disputes with NIMO which are unresolved.

Other U.S. Geothermal Interests

Roosevelt Hot Springs. A subsidiary of the Company operates
and owns an approximately 70% indirect interest in a geothermal
steam field which supplies geothermal steam to a 23 net MW power
plant owned by Utah Power & Light Company ("UP&L") located on the
Roosevelt Hot Springs property under a 30-year steam sales
contract. The Company obtained approximately $20.3 million of
cash under a pre-sale agreement with UP&L whereby UP&L paid in
advance for the steam produced by the steam field. The Company
must make certain penalty payments to UP&L if the steam produced
does not meet certain quantity and quality requirements.

Desert Peak. A subsidiary of the Company is the owner of a
10 net MW geothermal plant at Sparks, Nevada. In 1998 the
Company executed an agreement pursuant to which the Desert Peak
Project is leased to a third party power producer and the Company
receives rental payments.

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

United Kingdom Power Generation

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

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

Viking. Viking Power Limited ("Viking") is a company owned
50% by Northern and 50% by Rolls-Royce Power Ventures which
operates a 50 net MW natural gas-fired power plant at Seal Sands
on Teesside. The project utilizes an aero-derivative Rolls-Royce
Trent Engine and is embedded on the Northern distribution
network. Viking became operational in October 1998, has a long-
term gas supply and electricity off-take contract with Northern
and is being operated by Northern Generation.

The Philippines Power Generation
<PAGE>
Upper Mahiao. The Upper Mahiao facility has been in
commercial operation since June 17, 1996, although output was
constrained until 1998 because the required full capacity
transmission line was not completed and provided by the
Philippine National Power Corporation ("NPC") to CE Cebu
Geothermal Power Company, Inc. ("CE Cebu"), a Philippine
corporation that is 100% indirectly owned by the Company. During
the period of constrained operation, PNOC-EDC was required to,
and paid all capacity fees under the take or pay provisions of
the contract. In early 1998, the required transmission line was
completed, allowing unconstrained operation. As a result, CE
Cebu has been receiving capacity and energy payments from PNOC-
EDC since that time.

A consortium of international banks are providing the term
loans, supported by political risk insurance from the Ex-Im Bank.
Upon completion of the transmission line, the construction loan
was converted to a term loan in May 1998 provided by United
States Export-Import Bank and a local Philippine bank.

Under the terms of an energy conversion agreement, executed
on September 6, 1993 (the "Upper Mahiao ECA"), CE Cebu owns and
operates the Upper Mahiao Project during the ten-year cooperation
period, which commenced in June, 1996 after which ownership will
be transferred to PNOC-EDC at no cost.

The Upper Mahiao Project is located on land provided by PNOC-
EDC at no cost. It takes geothermal steam and fluid, also
provided by PNOC-EDC at no cost, and converts its thermal energy
into electrical energy sold to PNOC-EDC on a "take-or-pay" basis.
Specifically, PNOC-EDC is obligated to pay for 100% of the
electric capacity that is nominated each year by CE Cebu,
irrespective of whether PNOC-EDC is willing or able to accept
delivery of such capacity. PNOC-EDC pays to CE Cebu a fee (the
"Capacity Fee") based on the plant capacity nominated to PNOC-EDC
in any year (which, at the plant's design capacity, is
approximately 95% of total contract revenues) and a fee (the
"Energy Fee") based on the electricity actually delivered to PNOC-
EDC (approximately 5% of total contract revenues). Payments
under the Upper Mahiao ECA are denominated in U.S. dollars, or
computed in U.S. dollars and paid in Philippine pesos at the then-
current exchange rate, except for the Energy Fee. Significant
portions of the Capacity Fee and Energy Fee are indexed to U.S.
and Philippine inflation rates, respectively. PNOC-EDC's payment
requirements, and its other obligations under the Upper Mahiao
ECA, are supported by the Government of the Philippines through a
performance undertaking.

The payment of the Capacity Fee is not excused if PNOC-EDC
fails to deliver or remove the steam or fluids or fails to
provide the transmission facilities, even if its failure was
caused by a force majeure event. In addition, PNOC-EDC must
continue to make Capacity Fee payments if there is a force
majeure event (e.g., war, nationalization, etc.) that affects the
operation of the Upper Mahiao Project and that is within the
reasonable control of PNOC-EDC or the Government of the
Philippines or any agency or authority thereof.

PNOC-EDC is obligated to purchase CE Cebu's interest in the
facility under certain circumstances, including (i) extended
outages resulting from the failure of PNOC-EDC to provide the
required geothermal fluid, (ii) certain material changes in
policies or laws which adversely affect CE Cebu's interest in the
project, (iii) transmission failure, (iv) failure of PNOC-EDC to
make timely payments of amounts due under the Upper Mahiao ECA,
(v) privatization of PNOC-EDC or NPC, and (vi) certain other
events. The price will be the net present value (at a discount
rate based on the last published Commercial Interest Reference
Rate of the Organization for Economic Cooperation and
Development) of the total remaining amount of Capacity Fees over
the remaining term of the Upper Mahiao ECA.

Mahanagdong. The Mahanagdong Project is a 165 net MW
geothermal power project owned and operated by CE Luzon
Geothermal Power Company, Inc. ("CE Luzon"), a Philippine
corporation of which 100% of the common stock is indirectly owned
by the Company. Another industrial company owns an approximate
10% preferred equity interest in the project. The Mahanagdong
Project has been in commercial operation since July 25, 1997,
although its output was constrained until early 1998 because the
required full transmission line was not completed until that
time. The Mahanagdong Project sells 100% of its capacity on a
similar basis as described above for the Upper Mahiao Project to
<PAGE>
PNOC-EDC, which in turn sells the power to NPC for distribution
to the island of Luzon. During the period of constrained
operation, PNOC-EDC was required to, and paid all capacity fees
under the take or pay provisions of the contract.

The project financing term loan is being provided by OPIC,
Ex-Im Bank and a consortium of international banks. Upon
completion of the transmission line, the construction loan was
converted to a term loan in June, 1998. Political risk insurance
from Ex-Im Bank has been obtained for the commercial lenders.

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

Malitbog. The Malitbog Project is a 216 net MW geothermal
project owned and operated by Visayas Geothermal Power Company
("VGPC"), a Philippine general partnership that is wholly owned,
indirectly, by the Company. The three Units of the Malitbog
facility were put into commercial operation on July 25, 1996 (for
Unit I) and July 25, 1997 (for Units II and III), although as
with the Upper Mahiao and Mahanagdong projects, operation was
constrained due to a lack of the necessary transmission line.
VGPC is selling 100% of its capacity on substantially the same
basis as described above for the Upper Mahiao Project to PNOC-
EDC, which sells the power to NPC. During the period of
constrained operation, PNOC-EDC was required to, and paid all
capacity fees under the take or pay provisions of the contract.

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

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

PNOC-EDC is obligated to purchase VGPC's interest in the
facility under certain circumstances, including (i) certain
material changes in policies or laws which adversely affect
VGPC's interest in the project, (ii) any event of force majeure
which delays performance by more than 90 days and (iii) certain
other events. The price will be the net present value of the
capital cost recovery fees that would have been due for the
remainder of the Cooperation Period with respect to such
generating unit(s).

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

United States

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

The Zinc Recovery Project is being constructed by Kvaerner
U.S. Inc. ("Kvaerner") pursuant to a date certain, fixed-price,
turnkey engineering, procurement and construction contract (the
"Zinc Recovery Project EPC Contract"). Kvaerner is a wholly-
owned indirect subsidiary of Kvaerner ASA, an internationally
recognized engineering and construction firm experienced in the
metals, mining and processing industries.

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

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

Philippines

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

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

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

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

CE Casecnan entered into a fixed price, date certain,
turnkey engineering, procurement and construction contract to
complete the construction of the Casecnan Project (the "Casecnan
Construction Contract"). The work under the Casecnan
Construction Contract is being conducted by a consortium
consisting of Cooperativa Muratori Cementisti CMC di Ravenna and
Impresa Pizzarotti & C. Spa working together with Siemens A.G.,
Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering
Ltd. The construction of the Casecnan Project is proceeding on
schedule and is expected to be completed in 2000.
<PAGE>
Indonesia

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

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

PROJECTS IN DEVELOPMENT

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

United States

Salton Sea Minerals Extraction. In addition to zinc
recovery, the Company intends to sequentially develop manganese,
silver, gold, lead, boron, lithium and other products as it
further develops the extraction technology. If successfully
developed for the other products, the mineral extraction process
will provide an environmentally responsible and low cost minerals
recovery methodology. The Company is also investigating producing
silica from the solids precipitated out of the geothermal power
process. Silica is used as a filler for such products as paint,
plastics and high temperature cement.

Telephone Flat. The Company is developing a 48 net MW
geothermal project at Telephone Flat in Northern California where the
Company has two successful production wells (the "Telephone Flat
Project"). Under an amended contract arrangement with the Bonneville
Power Administration ("BPA"), BPA will purchase 30 MW from the
project and has an option to purchase an additional 100 MW. The
completion of the project and BPA's purchase obligation are subject
to obtaining a final environmental impact statement relating to the
new site location.
<PAGE>
Cordova. The power station is a nominal 500 MW gas-fired
generating plant that is targeted for completion in the late
spring of 2001. The preferred site for the power station is near
Cordova, Il., northeast of the Quad Cities. The Quad Cities
Energy Company has signed contracts for five major equipment
components for the planned electric power station near the Quad
Cities. The Quad Cities Energy Company which is developing the
project through a subsidiary, is a subsidiary of the Company.

With its strategic location in the Quad Cities area, it will
border on two electric reliability districts: the Mid-Continent
Area Power Pool and the MidAmerica Interconnected Network. The
plant will also feature highly efficient operations, flexible
transmission access and competitive gas supply.

United Kingdom

Exeter. Exeter Power Limited ("Exeter") is a company owned
50% by Northern Electric Generation Limited and 50% by Rolls-
Royce Power Ventures. Exeter is developing a 50 net MW gas-fired
power plant at Exeter, England. This project is based upon the
U.K. "Mid-merit" model (described below) and will be managed and
operated by Northern upon commercial operation. The power
purchase contract and permits for the project are currently being
finalized.

U.K. Mid-merit Projects. The Company, through Northern
Generation, is pursuing a number of "Mid-merit" project
opportunities in addition to Exeter and Viking, in conjunction
with and separate from Rolls-Royce. However, the gas moratorium
in the U.K. has significantly adversely impacted the ability to
develop these projects.

"Mid-merit" projects are those projects which have
generation units having a registered capacity of 50 net MW or
less. As a result, these projects only require local planning
permission and limited central government permits. In addition,
these projects are connected to the local distribution system and
not the National Grid, which means these projects do not have to
be a member of the Pool and pay generator related grid and Pool
charges. These Mid-merit generating projects are also not
subject to central dispatch by the National Grid and therefore
allow for the potential of gas arbitrage between the electricity
day-ahead pool market and the within-day gas spot market.

Finally, these projects are based on open (simple) cycle
aero derivative gas turbines which are ideally suited to multiple
start/stop operations. This flexible capability provides
significant economic benefits to Northern's electricity supply
business in buying electricity from the Mid-merit plant and
avoiding pool purchases at high pool price times and making Pool
purchases when the Pool price is below the Mid-merit plant's
marginal costs.

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

Producing Gas Field Operations and Fields in Development

CE Gas UK Limited. CE Gas UK Limited ("CE Gas") is a gas
exploration and production company which is focused on developing
integrated upstream gas projects. Its "upstream gas" business
consists of the exploration, development and production,
including transportation and storage, of gas for delivery to a
point of sale into either a gas supply market or a power
generation facility. CE Gas holds various interests in the
southern basin of the United Kingdom sector of the North Sea, as
described below. Also as is more fully discussed below, CE Gas
has recently been involved in certain gas development and
exploration activities relating to a large gas field prospect in
Poland and the Gingin field in the Perth Basin in Australia and
the Yolla discovery in the Bass Basin of Australia.
<PAGE>
The Company's Producing Gas Field Operations and Fields in
Development

PRODUCING GAS FIELDS SHARE OF CURRENT LOCATION
REMAINING % WORKING
RESERVES INTEREST
BCF1

Windermere 12.0 20.000% U.K. Offshore
(North Sea)
Victor 10.3 5.000% U.K. Offshore
(North Sea)
Schooner 10.0 2.078% U.K. Offshore
(North Sea)
Johnston 23.1 18.264%2 U.K. Offshore
(North Sea)
FIELDS IN DEVELOPMENT Size Km2

Pila Concession 13,0003 100% N.W. Poland
(Polish Trough)
Gingin Concession 2,960 36.000% S.W. Australia
Onshore
(Perth Basin)
Yolla Discovery 550 20.000% S.E. Australia
Offshore
(Botts Basin)

Producing Fields

Windermere Field. The Windermere Field is located in the
Eastern part of the Southern North Sea approximately 62 miles
east of Hull on the U.K. coast and has Remaining reserves of 12.0
bcf net to CE Gas. The field is produced by an unmanned platform
which has two wells. The gas is transported via an 8" pipeline to
the Markham Field where it is processed, compressed and delivered
through the K13 pipeline system to the Den Helder terminal on the
Netherlands coast. CE Gas holds a 20% working interest in this
field which commenced production in April 1997 and currently has
average net daily production of 9.0 MM scfd (million standard
cubic feet per day). Gas is sold to N.V. Nederlandse Gasunie.

Victor Field. The Victor gas field is located in the central
part of the Southern North Sea, approximately 80 miles east of
the Theddlethorpe terminal on the U.K. coast and has net
Remaining reserves of 10.3 bcf net to CE Gas. An unmanned
platform is installed and the field produces from 5 production
wells and a sixth subsea well tied back to the platform. The gas
is exported through a 16" pipeline to the Viking field and then
onwards to the Theddlethorpe shore terminal. The Victor field has
been in production since September 1984, and currently has
average daily production of 5.2 MM scfd and sells its gas to
British Gas Trading Limited. CE Gas holds a 5% working interest
in this field.

1 Gas reserves in Billion cubic feet (or "Bcf") as of December 31, 1998.
The Classification "Remaining" means reserves which geophysical, geological
and engineering data indicate to be in place or recoverable (as the case
may be) with a 50% probability the reserves will exceed the estimate.

2 Currently in the process of finalizing.

3 Subject to 25% relinquishment after every 2 years during the 8 year contract
term based on work program results.
<PAGE>
Schooner Field. The Schooner Field is located in the
Northern part of the Southern North Sea and has Remaining
reserves of 10.0 bcf. The field is produced by an unmanned
platform which is tied back through a 28km 16" flowline to the
Murdoch platform. Production is achieved from six wells with a
seventh well planned for 1999. The gas is transported through
the CMS pipeline to the Theddlethorpe shore terminal. CE Gas
holds a 2.078% working interest in the Schooner Field, which
commenced production in October 1996 and currently has average
net daily production of 2.4 MM scfd. The CE Gas share of the gas
is sold to Northern.

Johnston Field. The Johnston gas field is located in the
Southern North Sea approximately 56 miles north east of
Scarborough on the U.K. coast and has Remaining reserves of 23.1
bcf net to CE gas. The field is produced from three subsea wells
tied back to the Ravenspurn North field via a 4.5 mile, 12"
pipeline. Gas is exported via the Cleeton field to the
Dimlington terminal via a 33 mile, 36" pipeline. The Johnston
field has been in production since October 1994 at an average
daily rate of 53 MMscfd. Gas is sold to Eastern Natural Gas. CE
Gas has a 18.264% working interest in this field and is currently
in the process of finalizing an equity redefinition for this
field which is expected to increase our ownership to 22.113%.

Projects in Development

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

Gingin Gas Field. In August 1997, CE Gas signed an earn-in
agreement with Empire Oil of Australia, the permit holder for
various concession areas in the Gingin field in the Perth Basin
in Western Australia. The earn-in agreement provides CE Gas with
the ability, through a seismic and drilling phased work program,
to obtain up to a 50% working interest in the main concession
area totaling 2,960 square kilometers and up to a 33% working
interest in four ancillary concession areas totaling 9,451 square
kilometers. Gingin gas reserves are estimated by Empire Oil to be
470 bcf. Given the advantages of the location of the Gingin
field, in close proximity to an industrial area and electric
residential load center, the Company believes that the Gingin
field possesses the potential for an integrated upstream
gas/power generation project.

Both electricity and gas are in the process of being opened
up for competition in Australia. 95% of all gas to SW Australia
is currently supplied from the NW shelf (Dampier to Bunbury
pipeline--1500km). The Onshore Perth Basin is known to be gas
prone but has been significantly underexplored and
underdeveloped. Historically, gas has been a state controlled
energy sector in Australia. The Gingin field proved gas in the
early 1970s. The Company believes that new technologies now offer
the potential for extracting significant gas reserves through
more advanced recovery methods, and the Company, which currently
beneficially owns a 36% interest in the Gingin Concession, which
has been earned under a phased seismic and drilling work program
with Empire Oil of Australia.

Yolla Gas Discovery. The Yolla gas field was discovered in
1985 and is located offshore, approximately 120 kilometers from
the coast of Tasmania and 200 kilometers from the coast of
Victoria in Australia. In 1998, CEGas entered into an option
agreement with Boral Energy Resources Limited and Premier
Petroleum (Australia) Limited to earn interests in three permits
in the Bass Basin located in the south east of Australia,
including the Yolla gas discovery.

Regulatory, Energy and Environmental Matters
<PAGE>
United States

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

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

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

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

The Clean Air Act Amendments ("CAAA") were signed into law
in November 1990. MidAmerican Energy has five jointly owned and
six wholly owned coal-fired generating units, which represent
approximately 65% of MidAmerican Energy's electric generating
capability. Essentially all utility generating units are subject
to the provisions of the CAAA which address continuous emissions
monitoring, permit requirement and fees and emissions of certain
substances. Under current regulations, MidAmerican Energy does
not anticipate its construction costs for the installation of
<PAGE>
emissions monitoring system upgrades through 2000 to be material.
MidAmerican Energy's generating units meet all Title IV CAAA
requirements through 2007. Title IV of the CAAA, which is also
known as the Acid Rain Program, sets forth requirements for the
emission of sulfur dioxide and nitrogen oxides at electric
utility generating stations.

State and federal environmental laws and regulations
currently have, and future modifications may have, the effect of
(i) increasing the lead time for the construction of new
facilities, (ii) significantly increasing the total cost of new
facilities, (iii) requiring modification of certain of the
Company's existing facilities, (iv) increasing the risk of delay
on construction projects, (v) increasing the Company's cost of
waste disposal and (vi) possibly reducing the reliability of
service provided by the Company and the amount of energy
available from the Company's facilities. Any of such items could
have a substantial impact on amounts required to be expended by
the Company in the future.

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

United Kingdom

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

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

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

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

In March 1998 the United Kingdom Government published a
consultation on utility regulation. This paper outlined a number
of proposals for discussion. The stated objectives are "fairness
and efficiency" which the Government regard as "the key to
securing a long-term, stable and effective framework capable of
serving consumers well and of taking these industries into the
next millennium". Some of the proposals under consideration
would require legislative changes.
<PAGE>

Employees

At December 31, 1998, the Company and its subsidiaries
employed approximately 4,500 people. Neither the Falcon Projects
nor the Imperial Valley Project partnerships hire or retain any
employees. All employees necessary to operate the Falcon and
Imperial Valley Projects are provided by affiliates of the
Company under certain administrative services and operation and
maintenance agreements. International development activities in
Indonesia and the Philippines are principally performed by
employees of affiliates of the Company and operations will be
performed by employees of the local project entities. The
Company's Indonesian and Philippine affiliates currently maintain
offices in Manila and Jakarta.

Of Northern's employees, at December 31, 1998, approximately
75% are represented by labor unions. All Northern employees who
are not party to a personal employment contract are subject to
collective bargaining agreements that are covered by eight
separate business agreements. These arrangements may be amended
by joint agreement between the trade unions and the individual
business through negotiation in the appropriate Joint Business
Council. Northern believes that its relations with its employees
are good.

MidAmerican Energy and its affiliates (other than
MidAmerican Realty Services) employed approximately 3,900 as of
December 31, 1998 approximately one half of which are represented
by labor unions. MidAmerican Realty Services and its affiliates
employed more than 1,150 persons and retained an additional 4,500
sales agents as of December 31, 1998. MidAmerican Energy
believes that its relations with its employees are good.

Item 2. Properties

Property. Northern owns the freehold of its principal
executive offices in Newcastle upon Tyne, England. Northern has
both network and non-network land and building. At December 31,
1998, Northern had freehold and leasehold interests in
approximately 7,500 network properties, comprising principally
sub-station sites. The recorded historical cost account net book
value of total network land and buildings at December 31, 1998
was pounds sterling 23.9 million. Northern owns, directly or
indirectly, the freehold or leasehold interests of such land and
buildings. At December 31, 1998 Northern had freehold and
leasehold interests in approximately 95 non-network properties
comprising chiefly offices, former retail outlets, depots,
warehouses and workshops. The recorded historical cost account
net book value of total non-network land and buildings at
December 31, 1998 was pounds sterling 25.6 million.

MidAmerican Energy's utility properties consist of physical
assets necessary and appropriate to rendering electric and gas
service in its service territories. Electric property consists
primarily of generation, transmission and distribution
facilities. Gas property consists primarily of distribution
plant, including feeder lines to communities served from natural
gas pipelines owned by others. It is the opinion of management
that the principal depreciable properties owned by MidAmerican
Energy are in good operating condition and well maintained. The
electric transmission system of MidAmerican Energy at December
31, 1998, included 896 miles of 345-kV lines, 1,294 miles of 161-
kV lines, 1,796 miles of 69-kV lines and 34.5-kV lines. The gas
distribution facilities of MidAmerican Energy at December 31,
1998, included 19,428 miles of gas mains and services.
Substantially all the former Iowa-Illinois Gas and Electric
Company (predecessor to MidAmerican Energy) utility property and
franchises, and substantially all of the former Midwest Power
Systems Inc. (predecessor to MidAmerican Energy) electric utility
property located in Iowa, or approximately 80% of gross utility
plant, is pledged to secure mortgage bonds.

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

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

Item 3. Legal Proceedings

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

Item 4. Submission of Matters to a Vote of Security Holders.

Not applicable.
<PAGE>
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder's Matters

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

PRICE RANGE

HIGH LOW

Fiscal Year Ending December
31, 1998

Fourth Quarter 34.6875 24.6875
Third Quarter 30.6875 22.9375
Second Quarter 33.8125 28.1875
First Quarter 31.3125 23.25

Fiscal Year Ending December
31, 1997

Fourth Quarter 39.625 28.00
Third Quarter 41.75 30.9375
Second Quarter 41.625 32.625
First Quarter 38.375 32.125

Fiscal Year Ending December
31, 1996

Fourth Quarter 33.625 28.125
Third Quarter 31.875 22.875
Second Quarter 28.375 24.00
First Quarter 26.875 18.375

On March 29, 1999, the last reported sale price of the
Common Stock on the NYSE Composite Tape was $27 15/16 per share.
As of March 29, 1999, there were approximately 1,042 holders of
record of the Common Stock. The Company's present policy is to
reinvest earnings in the business and pay no dividends on its
Common Stock.

The Company's 9 1/2% senior notes due 2006 and the Company's
7.63% senior notes due 2007 restrict the payment of cash
dividends based upon a formula and limit the amount of dividends
and other distributions generally to no more than 50% of the
Company's accumulated adjusted consolidated net income as
defined, subsequent to April 1, 1994, plus the proceeds of any
stock issuance.

The Company's ability to pay dividends is dependent upon
receipt of dividends or other distributions from the Company's
subsidiaries and the partnerships and joint ventures in which the
Company has interests. The availability of distributions from the
Company's subsidiaries is subject to the satisfaction of various
covenants and conditions contained in the venture's financing
documents (such as those contained in the Salton Sea Funding or
international project financing documents) and the Company
anticipates that future project level financings will contain
certain conditions and similar restrictions on the distribution
of cash flow to the Company.
<PAGE>
Item 6. Selected Financial Data

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

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

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

Item 7A. Qualitative and Quantitative Disclosures About Market
Risk

There is hereby incorporated by reference the information
which appears under the caption "Qualitative and Quantitative
Disclosures About Market Risk" in the Annual Report.

Item 8. Financial Statements and Supplementary Data

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

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

Not applicable.
<PAGE>
PART III

MANAGEMENT

Item 10. Directors, Executive and Other Officers of the Company
and Significant Subsidiaries

There is hereby incorporated by reference the information
which appears under the caption "Information Regarding Nominees
for Election as Directors and Directors Continuing in Office at
the Annual Meeting" in the Proxy Statement. The Company's
management structure is organized functionally and the current
executive and other officers of the Company and their positions
are as follows:

Name Position Company

David L. Sokol Chairman of the Board and Chief Executive Officer MEHC, MEC,
Northern
Gregory E. Abel President and Chief Operating Officer MEHC,
Northern
Alan L. Wells Senior Vice President and Chief Financial Officer MEHC, MEC
Steven A. McArthur Senior Vice President, Mergers and
Acquisitions and Secretary MEHC
John A. Rasmussen Senior Vice President and General Counsel MEHC, MEC
Patrick J. Goodman Senior Vice President and Chief Accounting Officer MEHC, MEC
Robert S.Silberman Senior Vice President and Chief
Administrative Officer MEHC
Douglas L. Anderson Vice President and Assistant General Counsel MEHC
Edward F. Bazemore Vice President, Human Resources/IPP MEHC
Robert Beck Director, Year 2000 Worldwide Project MEHC
Vincent R. Fesmire Vice President, Construction and Engineering MEHC
James A. Flores Vice President, Project Finance MEHC
Adrian M. Foley III Vice President, Marketing MEHC
Ronald J. Giaier Vice President, Investor Relations and
Risk Management MEHC
Brian K. Hankel Vice President and Treasurer MEHC
Keith D. Hartje Vice President, Human Resources MEHC
Paul J. Leighton Vice President Corporate Law, Assistant
General Counsel and Assistant Secretary MEHC
Joseph M. Lillo Director Financial Reporting and
Controller/IPP MEHC
Frederick L. Manuel Senior Vice President, CalEnergy Generation MEHC
Christoph F. Minor Vice President, Information Technology MEHC
Patti J. McAtee Vice President, Corporate Communications MEHC
James J. Sellner Director of Taxation, Corporate MEHC
K. Taylor Smith General Manager, Indonesia and
Controller, Asian Operations MEHC
Jonathan M. Weisgall Vice President, Federal Regulation/IIPP MEHC
Russell H. White Assistant Vice President, General Services MEHC
Cathy S. Woollums Vice President, Environmental MEHC
Ronald W. Stepien President MEC
Jack L. Alexander Senior Vice President, Transmission & Energy
Delivery MEC
David C. Caris Vice President, State Government Affairs MEC
Dwayne J. Coben Vice President, Utility Development MEC
Steven J. Dust Vice President, Economic Development and
Community Relations MEC
Brent E. Gale Vice President, Legislation and Regulation MEC
James J. Howard Vice President, Regulatory Affairs MEC
David J. Levy Senior Vice President Retail MEC
J. Sue Rozema Vice President Financial Services MEC
Larry M. Smith Vice President and Controller MEC
Steven R. Weiss Assistant General Counsel MEC
Beverly A. Wharton Senior Vice President, State Government
Affairs and Regulation MEC
<PAGE>
P. Eric Connor Director and Managing Director, Utility Services Northern
Malcolm Chandler Director and Managing Director, Supply Northern
Ian S.R. Colquhoun Managing Director, Northern Metering Services Northern
Dave Crompton Managing Director, Retail Northern
Alan Dickson Manager, Tax Northern
David A. Faulkner Director, Personnel and Corporate Affairs Northern
Dr.John M. France Director of Regulation Northern
G. Valerie Giles Company Secretary Northern
Dr.Philip S.Lawless Managing Director, Generation Northern
Ken Linge Director of Finance Northern
David Pearson Managing Director, Marketing and Sales Northern
Steve Raine Director, Information Systems Technology Northern
James D.Stallmeyer Vice President and General Counsel Northern
David Swan Managing Director, Distribution Director Northern
David A. Waters Managing Director, Northern Utility Services Northern
Peter Youngs Managing Director, Gas Exploration and Development Northern

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

DAVID L. SOKOL, 42, Chairman of the Board of Directors and
Chief Executive Officer. Mr. Sokol has been CEO since April 19,
1993 and served as President of MEHC from April 19, 1993 until
January 21, 1995. Mr. Sokol has been Chairman of the Board of
Directors since May 1994 and a director since March 1991.
Formerly, among other positions held in the independent power
industry, Mr. Sokol served as President and Chief Executive
Officer of Kiewit Energy Company, which at that time was a wholly
owned subsidiary of PKS, and Ogden Projects, Inc.

GREGORY E. ABEL, 36, President and Chief Operating Officer.
Mr. Abel joined the Company in 1992. Mr. Abel is a Chartered
Accountant and from 1984 to 1992 he was employed by Price
Waterhouse. As a Manager in the San Francisco office of Price
Waterhouse, he was responsible for clients in the energy
industry.

ALAN L. WELLS, 39, Senior Vice President and Chief Financial
Officer. Mr. Wells has been Senior Vice President and Chief
Financial Officer of MidAmerican Energy since November 1, 1997,
and was Vice President of MidAmerican Energy from November 1,
1996 to November 1, 1997. Mr. Wells held various executive and
management positions with MidAmerican Energy from July 1, 1995 to
November 1, 1996, and various executive and management positions
with Iowa-Illinois Electric and Gas from 1993 to 1995. .

STEVEN A. McARTHUR, 41, Senior Vice President, Mergers and
Acquisitions and Secretary. Mr. McArthur joined the Company in
February 1991. From 1988 to 1991 he was an attorney in the
Corporate Finance Group at Shearman & Sterling in San Francisco.
From 1984 to 1988 he was an attorney in the Corporate Finance
Group at Winthrop, Stimson, Putnam & Roberts in New York.

JOHN A. RASMUSSEN, JR., 53, Senior Vice President and
General Counsel. Mr. Rasmussen has been Senior Vice President and
General Counsel of MidAmerican Energy since November 1, 1996, and
Group Vice President and General Counsel from July 1, 1995 to
November 1, 1996. Prior to that he was Vice President and
General Counsel of Midwest Power Systems, Inc., a predecessor
company, from 1993 to 1995.

PATRICK J. GOODMAN, 32, Senior Vice President and Chief
Accounting Officer. Mr. Goodman joined the Company in June 1995,
and served as Manager of Consolidation Accounting until September
1996 when he was promoted to Controller. Prior to joining the
Company, Mr. Goodman was a financial manager for National
Indemnity Company and a senior associate at Coopers & Lybrand.

ROBERT S. SILBERMAN, 41, Senior Vice President and Chief
Administrative Officer. Mr. Silberman joined the Company in 1995.
Prior to that, Mr. Silberman served as Executive Assistant to the
Chairman and Chief Executive Officer of International Paper
Company, as Director of Project Finance and Implementation for
the Ogden Corporation and as a Project Manager in Business
Development for Allied-Signal, Inc. He has also served as the
Assistant Secretary of the Army for the United States Department
of Defense.
<PAGE>
DOUGLAS L. ANDERSON, 41, Vice President and Assistant
General Counsel. Mr. Anderson joined the Company in February
1993. From 1990 to 1993, Mr. Anderson was a business attorney
with Fraser, Stryker, Vaughn, Meusey, Olson, Boyer & Bloch, P.C.
in Omaha. From 1987 through 1989, Mr. Anderson was a principal in
the firm Anderson & Anderson. Prior to that, from 1985 to 1987,
he was an attorney with Foster, Swift, Collins & Coey, P.C. in
Lansing, Michigan.

EDWARD F. BAZEMORE, 62, Vice President, Human Resources/IPP.
Mr. Bazemore joined the Company in July 1991. From 1989 to 1991,
he was Vice President, Human Resources, at Ogden Projects, Inc.
in New Jersey. Prior to that, Mr. Bazemore was Director of Human
Resources for Ricoh Corporation, also in New Jersey. Previously,
he was Director of Industrial Relations for Scripto, Inc. in
Atlanta, Georgia.

ROBERT BECK, 37, Director, Year 2000 Worldwide Project. Mr.
Beck has been with the company since 1996. He was previously
Director, Corporate Information Systems with the Company. Prior
to joining the company, Mr. Beck was an executive with Inacom
Corporation and has held senior management positions with AT&T
and US West.

VINCENT R. FESMIRE, 58, Vice President, Construction and
Engineering. Mr. Fesmire joined the Company in October 1993.
Since joining CalEnergy, Mr. Fesmire's responsibilities have
shifted from project development and implementation to
construction in parallel with the status of the Company's
projects. Prior to joining the Company, Mr. Fesmire was employed
for 19 years with Stone & Webster, an engineering firm, serving
in various management level capacities with an expertise in
geothermal design engineering.

JAMES A. FLORES, 45, Vice President, Project Finance. Prior
to joining CalEnergy in May 1994, Mr. Flores was employed for 12
years with Mellon Bank, first in its Latin American Group and
subsequently in its Project Finance Group.

ADRIAN M. FOLEY, III, 52, Vice President, Marketing. Mr.
Foley joined the Company in January 1994 as Project Development
Manager and continued in that capacity until January 1997 when he
was promoted to Vice President, Marketing. Prior to joining
CalEnergy, Mr. Foley was Regional Manager, Business Development
with Ogden Projects, Inc. from 1989 to 1993 and Executive Vice
President with Rescom Development Company from 1980 to 1989.

RONALD J. GIAIER, 50, Vice President, Investor Relations and
Risk Management. Mr. Giaier joined MidAmerican Energy in
February, 1998. Mr. Giaier was previously Assistant Treasurer-
Finance and Investor Relations of DTE Energy and Detroit Edison,
its largest subsidiary, Detroit, Michigan. Previously, Mr.
Giaier, who had been with DTE Energy since 1970, had been
Director of Finance and Investor Relations.

BRIAN K. HANKEL, 36, Vice President and Treasurer. Mr.
Hankel joined the Company in February 1992 as Treasury Analyst
and served in that position to December 1995. Mr. Hankel was
appointed to Assistant Treasurer in January 1996 and was
appointed Treasurer in January 1997. Prior to joining the
Company, Mr. Hankel was a Money Position Analyst at FirsTier Bank
of Lincoln from 1988 to 1992 and Senior Credit Analyst at
FirsTier from 1987 to 1988.

KEITH D. HARTJE, 50, Vice President, Human Resources. Mr.
Hartje has been with MidAmerican Energy Company and its
predecessor companies since 1973. In that time, he has held a
number of positions with the company, including General Counsel
and Corporate Secretary, District Vice President for southwest
Iowa operations, and Vice President, Corporate Communications.
<PAGE>
PAUL J. LEIGHTON, 45, Vice President, Corporate Law,
Assistant General Counsel and Assistant Secretary. Mr. Leighton
has served as Corporate Secretary for MidAmerican Energy and its
predecessor companies since 1988 and as an attorney since 1978.

JOSEPH M. LILLO, 29, Director, Financial Reporting and
Controller/IPP. Mr. Lillo joined Company in November 1996, and
served as Manager of Financial Reporting and was promoted to
Controller/IPP in March 1998. Prior to joining the Company, Mr.
Lillo was a senior associate with Coopers & Lybrand LLP.

FREDERICK L. MANUEL, 40, Senior Vice President, CalEnergy
Generation. Mr. Manuel joined the Company in 1991. Prior to that,
he was employed by Chevron Corporation with responsibilities
including land and offshore drilling, reservoir and production
engineering, project management and technical research.

PATTI J. MCATEE, 41, Vice President, Corporate
Communications. Ms. McAtee joined the Company in 1995. Ms.
McAtee was previously employed by Bergan Mercy Medical Center
since 1984. Since 1990 she was Marketing and Public Relations
Manager for the hospital.

JAMES J. SELLNER, 52, Director, Taxation. Mr. Sellner
joined CalEnergy in November, 1997. Prior to joining CalEnergy,
Mr. Sellner was employed by Central and South West Corporation
and Banc One/MCorp.

K. TAYLOR SMITH, 42, General Manager, Indonesia and
Controller, Asian Operations. Mr. Smith joined the Company in
1991. From 1986 to 1991 Mr. Smith was employed by Computer
Technology Associates, Inc. with responsibilities including
computer systems design and development, financial planning and
management.

JONATHAN M. WEISGALL, 50, Vice President, Federal
Regulation/IPP. Mr. Weisgall joined the Company in May 1995.
Prior to that, Mr. Weisgall was an attorney in private practice
with extensive energy and regulatory experience and is currently
Adjunct Professor of Energy Law at Georgetown University Law
Center.

RUSSELL H. WHITE, 52, Assistant Vice President, General
Services. Mr. White was previously Manager, General Services.
Mr. White joined the Company in 1988 as Manager, Asset
Protection.

CATHY WOOLLUMS, 38, Vice President, Environmental. Ms.
Woollums was an Attorney for Iowa-Illinois Gas and Electric
Company from 1991-1995. From 1995-1998, she was Manager,
Environmental Services with MidAmerican Energy Company.

RONALD W. STEPIEN, 52, President, MidAmerican Energy Company
since November 1, 1998, and Chief Operating Officer since March
1999, Executive Vice President from November 1, 1996 to October
31, 1998, and Group Vice President from 1995 to November 1, 1996.
Vice President of Iowa-Illinois Gas and Electric Company (Iowa-
Illinois), a predecessor company, from 1990 to 1995.

JACK L. ALEXANDER, 51, Senior Vice President, Transmission &
Energy Delivery. Mr. Alexander has been Senior Vice President of
MidAmerican Energy since November 1, 1998 and was a Vice
President of MidAmerican Energy from November 1, 1996 to October
31, 1998, and held various executive and management positions
with MidAmerican and Midwest Power Systems Inc., a predecessor
company, for more than five years prior thereto.

DAVE CARIS, 39, Vice President, State Government Affairs,
MidAmerican Energy Company. Mr. Caris was Government Affairs
Vice President for MidAmerican Energy from November 1, 1997 to
March 19, 1999 and Manager of Government Affairs for Iowa-
Illinois Gas & Electric Company, a predecessor company, from 1986-
1995.
<PAGE>
DWAYNE J. COBEN, 40, Vice President, Utility Development,
MidAmerican Energy Company. Mr. Coben has been with MidAmerican
Energy since August, 1997. He was Director, Corporate
Development from August 4 to March 1988 and Corporate Development
Vice President from April, 1998 to March, 1999. Prior to joining
MidAmerican Energy, Mr. Coben was Controller, Customer Services
for BC Hydro from December, 1994 to August, 1997 and held various
business development management positions with BC Hydro from 1990
to 1997.

STEVEN J. DUST, 44, Vice President, Economic Development and
Community Relations, MidAmerican Energy Company. Mr. Dust has
been in his present position since February, 1999. Mr. Dust has
over twenty year's experience in the economic development field
and joined MidAmerican Energy as Manager of Economic Development
in 1996. Prior to joining MidAmerican, Steve was a Principal of
Septagon Industries, a Midwest firm with holdings in industrial
construction, real estate development, manufacturing, and
communications.

BRENT E. GALE, 47, Vice President, Legislative and
Regulatory. Mr. Gale has previously held positions with
MidAmerican Energy as Vice President - Regulatory Law and
Analysis and Vice President - Law & Regulation. Prior to 1995,
Mr. Gale was Vice President - General Counsel of Iowa-Illinois
Gas and Electric Company, a predecessor of MidAmerican Energy.

JAMES J. HOWARD, 56 Vice President, Regulatory Affairs,
MidAmerican Energy Company. Mr. Howard has been Vice President,
Regulatory Affairs since April, 1998. Previously he had been
Vice President, Administrative Services since 1989.

DAVID J. LEVY, 44, Senior Vice President, Retail,
MidAmerican Energy Company. Mr. Levy has held this position
since November 1, 1996, and Vice President from 1995 to November
1, 1996 and was a Vice President of Iowa-Illinois from 1993 to
1995.

J. SUE ROZEMA, 46, Vice President, Financial Services,
MidAmerican Energy Company. Ms. Rozema has been Vice President,
Financial Services of MidAmerican Energy since March, 1998, Vice
President and Treasurer from July, 1996 to March, 1998, and Vice
President, Investor Relations from July, 1995 to July, 1996.
Prior to that she was Vice President and Treasurer of Midwest
Resources, a predecessor company.

LARRY M. SMITH, 43, Vice President and Controller,
MidAmerican Energy Company. Mr. Smith has held this position
since November 1996. Prior to that he was Controller of
MidAmerican Energy or one of it predecessors since 1990.

STEVEN R. WEISS, 44, Assistant General Counsel. Mr. Weiss
has been with MidAmerican Energy and its predecessor companies
since 1987 providing support to both the regulated and
competitive sides of the business. He was appointed to his
current position in March 1999. Prior to joining MidAmerican
Energy he served as a Hearing Examiner for the Illinois Commerce
Commission from 1982 until 1987.

BEVERLY A. WHARTON, 45, Senior Vice President, State
Government Affairs and Regulation, MidAmerican Energy Company.
Ms. Wharton has held this position since November 1996, and
President, Gas Division from 1995 to October 31, 1996 and was
Group Vice President of Midwest from 1992 to 1995. Director of
The Security National Bank of Sioux City.

IAN S. R. COLQUHOUN, 49, Managing Director, Northern
Metering Services. Mr. Colquhoun has spent more than 20 years in
Northern Electric with 14 years in management including two years
as a Personnel and Training Manager prior to his current
appointment. Mr. Colquhoun was appointed to his present post in
November 1998.

ERIC CONNOR, 50, Director, Northern Electric and Managing
Director, Utility Services. Mr. Connor joined Northern in 1992 as
a Director. Prior to joining Northern, he was a Director at NEI
<PAGE>
Reyrolle Ltd. and prior to that, his appointments included:
deputy group head of engineering, National Nuclear Corporation;
manager computer systems, NEI Electronics (C&I Systems); systems
engineer, Davy-Leowy; software engineer, Marconi Space & Defence.

DAVE CROMPTON, 45, Managing Director, Northern Electric
Retail. Mr. Crompton joined Northern Electric Retail in April
1990 where he served as Sales Director, and earlier this year
also took over the Marketing function. He became Managing
Director in June 1997. During his time with Northern Electric he
has gained a Master in Business Administration at Durham
University. Mr. Crompton has 26 years experience in electrical
retailing of which 19 years were with Dixons/Currys where he held
the posts of Regional Sales Manager and Divisional Marketing
Manager.

MALCOLM CHANDLER, 56, Director, Northern Electric and
Managing Director, Supply. Mr. Chandler joined Northern in 1970
from Manweb as Tariffs Engineer. His management positions have
included Tariffs & Supplies Manager, Regional Manager and
Director of Tariffs & Contracts.

ALAN DICKSON, 50, Tax Manager, Northern Electric. Mr.
Dickson joined Northern in September 1989. Prior to that Mr.
Dickson served in various posts with the Inland Revenue and as
District Inspector, Hexham.

DAVID A. FAULKNER, 51, Director, Personnel and Corporate
Affairs, Northern Electric. Mr. Faulkner's management positions
with the Company have included Industrial Relations Manager,
Privatization Manager and Director of Corporate Affairs, to which
he added responsibility for Personnel and Training in 1994.

DR. JOHN M. FRANCE, 41, Director of Regulation, Northern
Electric. Mr. France joined Northern in 1989. From 1982 to 1989,
Mr. France held a number of regulatory positions with British
Gas.

G. VALERIE GILES, 47, Company Secretary, Northern Electric.
Ms. Giles joined Northern Electric in 1989. From 1987 to 1989 she
was Assistant Company Secretary at Amersham International plc and
worked in their legal department from 1974 to 1987.

DR. PHILIP S. LAWLESS, 37, Managing Director, Generation,
Northern Electric. Mr. Lawless joined Northern in 1989 as
Contract Development Officer (Power Purchase). His previous
positions in Northern include Project Manager-Teesside Power
Limited and Generation Projects Manager. Prior to joining
Northern, he worked at NEI Parsons Ltd, where he held various
positions, and North Kalgurlie Mines Ltd, Australia, as an
Assistant Plant Metallurgist.

KEN LINGE, 49, Director of Finance, Northern Electric. Mr.
Linge joined Northern as an accountancy trainee in 1968. He has
held a variety of finance posts. In charge of Financial Planning
since 1987, he has been involved in privatization, regulatory
reviews and financial and treasury functions.

DAVID PEARSON, 44, Managing Director, Marketing and Sales,
Northern Electric. Mr. Pearson joined Northern in 1992 as
Managing Director, Retail. Prior to that his directorships
included Midlands Electricity, Sodexho, Thorn EMI, and Moulinex
UK. He also held management positions at General Foods and
Gilette.

STEVE RAINE, 52, Director, Information Systems Technology,
Northern Electric. Mr. Raine's appointments have included: Head
of Computer Services for North Yorkshire County Council; Director
of IT at Northern; General Manager and Executive Director of
Northern Information Systems (NIS). He currently represents the
UK electricity industry in UNIPEDE (the European electricity
utility forum) on IT matters and is a member of the UK
Electricity Pool Programme Board responsible for delivery of the
new trading systems for the opening up of the electricity market.

JAMES D. STALLMEYER, 41, Vice President and General Counsel,
Northern Electric. Mr. Stallmeyer joined the Company in 1993.
<PAGE>
Mr. Stallmeyer practiced in the public finance and banking areas
at Chapman and Cutler in Chicago from 1984 to 1987 and in the
corporate finance department from 1989 to 1993. Prior to that,
Mr. Stallmeyer was an attorney in the public finance department
of the Chicago office of Skadden, Arps, Slate, Meagher & Flom in
1987 and 1988 and was a legal writing instructor at the
University of Illinois College of Law in 1988 and 1989.

DAVID SWAN, 54, Director, Northern Electric and Managing
Director, Distribution. Mr. Swan joined Northern in 1966 and has
held posts in varying disciplines including distribution,
engineering design, operations, customers engineering, customer
relationships, engineering contracting, logistics, computer
systems development and project management.

DAVID A. WATERS, 56, Managing Director, Northern Utility
Services. Mr. Waters joined Northern in September 1960 as a
Student Apprentice. In 1982 he became a Resources Engineer and
received appointments as Cleveland (Teesside) Technical
Distribution System Planning Manager, Business Development
Manager, later promoted to Business Services Manager and General
Manager, NUSL. The following March 1998 he was appointed as
Managing Director.

PETER YOUNGS, 44, Managing Director, Gas Exploration and
Development. Mr. Youngs joined Neste Oy in 1974 as a Geoscientist
and held the following positions within the company:
International Exploration Manager, General Manager (Europe-Africa
Region), Vice President and Managing Director UKEXPRO. From 1994
to present, he has been the General Manager of CalEnergy Gas (UK)
Limited.
<PAGE>
PART IV

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

(a) Financial Statements and Schedules

1. Financial Statements

Filed herewith and incorporated by reference are
the consolidated balance sheets of the Company and subsidiaries
as of December 31, 1998 and 1997, and the consolidated statements
of operations, cash flows and stockholders' equity for the years
ended December 31, 1998, 1997 and 1996, and the related report of
independent auditors.

2. Financial Statement Schedules

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

(b) Reports on Form 8-K

The Company filed a joint Current Report on Form 8-K
dated October 13, 1998 with MidAmerican Energy Holdings Company
reporting the waiting period under the Hart-Scott-Rodino
Antitrust Improvement Act of 1976 expired and federal antitrust
clearance had been obtained for the proposed merger.

The Company filed a joint Current Report on Form 8-K
dated October 30, 1998 with MidAmerican Energy Holdings Company
reporting that in separate meetings held on October 30, 1998
shareholders approved the proposed merger of the companies.

The Company filed a Current Report on Form 8-K dated
November 10, 1998 reporting the pricing of its offering of $100
million aggregate principal amount of its 7.52% Senior Notes due
2008.

The Company filed a Current Report on Form 8-K dated
November 13, 1998 reporting the closing of its offering of $100
million aggregate principal amount of its 7.52% Series Notes due
2008.

The Company filed a Current Report on Form 8-K dated
November 30, 1998 reporting the amendment to its existing Rights
Agreement dated as of December 1, 1988

The Company filed a Current Report on Form 8-K dated
December 15, 1998 reporting the redemption on January 15, 1999
all of its outstanding 10 1/4% Senior Discount Notes due 2004.

The Company filed a joint Current Report on Form 8-K
dated December 16, 1998 with MidAmerican Energy Holdings Company
reporting FERC issuing an order approving the planned merger and
an order requiring 50% divestiture of CE's various QF's.

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

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

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

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

Not applicable.

<PAGE>
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned
thereunto duly authorized, in the City of Omaha, State of
Nebraska, on this 30th day of March, 1999.

MIDAMERICAN ENERGY HOLDINGS COMPANY

/s/ David L. Sokol*
By David L. Sokol
Chairman of the Board and Chief
Executive Officer

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

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

Signature Date

/s/ David L. Sokol* March 30,1999
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and
Director

/s/ Gregory E. Abel* March 30,1999
Gregory E. Abel
President and Chief Operating Officer

/s/ Alan L. Wells* March 30, 1999
Alan L. Wells
Senior Vice President and
Chief Financial Officer

/s/ Patrick J. Goodman* March 30,1999
Patrick J. Goodman
Senior Vice President and
Chief Accounting Officer

/s/ Edgar D. Aronson* March 30, 1999
Edgar D. Aronson
Director

*By:/s/ Steven A. McArthur March 30,1999
Steven A. McArthur
Attorney-in-Fact
<PAGE>
/s/ Judith E. Ayres* March 30,1999
Judith E. Ayres
Director

_______________________ March 30, 1999
Terry E. Branstad
Director

_______________________ March 30, 1999
Stanley J. Bright
Director

_______________________ March 30, 1999
Jack W. Eugster
Director

/s/ Richard R. Jaros* March 30, 1999
Richard R. Jaros
Director

/s/ David R. Morris* March 30,1999
David Morris
Director

_______________________ March 30, 1999
Robert L. Peterson
Director

/s/ John R. Shiner* March 30,1999
John R. Shiner
Director

/s/ Bernard W. Reznicek* March 30,1999
Bernard W. Reznicek
Director

/s/ Walter Scott, Jr.* March 30, 1999
Walter Scott, Jr.
Director

/s/ David E. Wit* March 30,1999
David E. Wit
Director

*By:/s/ Steven A. McArthur March 30,1999
Steven A. McArthur
Attorney-in-Fact
<PAGE>
EXHIBIT INDEX

3.1 Amended and Restated Articles of Incorporation of the
Company (incorporated by reference to Annex VI to the
Company's Joint Proxy Statement, dated September 25, 1998).

3.2 * Articles of Merger of Maverick Reincorporation Sub, Inc. and
CalEnergy Company, Inc. effective as of March 12, 1999.

3.3 * Articles of Amendment to the Amended and Restated Articles
of Incorporation of Maverick Reincorporation Sub, Inc.,
effective as of March 12, 1999 (name change to MidAmerican
Energy Holdings Company).

3.4 * Articles of Amendment to the Amended and Restated Articles
of Incorporation of the Company dated as of March 12, 1999
(preferred stock rights).

3.5 The Company's Amended and Restated By-Laws (incorporated by
reference to Exhibit 4.3 of the Company's Form S-8, dated
March 19, 1999, Registration No. 333-74691).

4.1 Specimen copy of form of Common Stock Certificate
(incorporated by reference to Exhibit 4.1 to the Company's
Form S-8, dated March 19, 1999, Registration No. 333-74691).

4.2 Shareholders Rights Agreement between the Company and
Manufacturers Hanover Trust Company of California dated
March 12, 1999 (incorporated by reference to Exhibit 1 to
the Company's Form 8-A, dated as of March 12, 1999, File No.
1-14881).

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

4.4 Indenture, dated as of September 20, 1996, between the
Company and IBJ Schroder Bank & Trust Company, as trustee,
relating to $225,000,000 principal amount of 9 1/2% Senior
Notes due 2006 (incorporated by reference to Exhibit 4.1 to
the Company's Registration Statement on Form S-3,
Registration No. 333-15591).

4.5 Indenture for the 6 1/4% Convertible Junior Subordinated
Debentures due 2012, dated as of February 26, 1997, between
the Company, as issuer, and the Bank of New York, as Trustee
(incorporated by reference to Exhibit 10.129 to the
Company's 1996 Form 10-K).

4.6 Registration Rights Agreement, dated August 12, 1997, by and
among CalEnergy Capital Trust III, CalEnergy Company, Inc.,
Credit Suisse First Boston Corporation and Lehman Brothers,
Inc. (incorporated by reference Exhibit 10.1 to the
Company's Registration Statement and on Form S-3, No. 333-
45615).

4.7 Indenture, dated as of October 15, 1997, among the Company
and IBJ Schroder Bank & Trust Company, as Trustee
(incorporated by reference to Exhibit 4.1 to the Company's
Current Report on Form 8-K dated October 23, 1997).

4.8 Form of First Supplemental Indenture, dated as of October
28, 1997, among the Company and IBJ Schroder Bank & Trust
Company, as Trustee (incorporated by reference to Exhibit
4.2 to the Company's Current Report on Form 8-K dated
October 23, 1997).

4.9 Form of Second Supplemental Indenture, dated as of September
22, 1998 between the Company and IBJ Schroder Bank & Trust
Company, as Trustee (incorporated by reference to Exhibit 4.1 to
the Company's Current Report on Form 8-K dated September 17,
1998.)
<PAGE>
4.10 Form of Third Supplemental Indenture, dated as of November
13, 1998, between the Company and IBJ Schroder Bank & Trust
Company, as Trustee (incorporated by reference to the Company's
Current Report on Form 8-K dated November 10, 1998).

10.1 1996 Employee Stock Option Plan, as amended (incorporated by
reference to Exhibit A to the Company's 1996 Proxy
Statement, 1997 Proxy Statement and 1998 Proxy Statement).

10.2 1994 Employee Stock Purchase Plan, as amended (incorporated
by reference to Exhibit A to the Company's 1994 Proxy
Statement).

10.3 Amended and Restated Employment Agreement between the
Company and David L. Sokol dated as of August 21, 1995
(incorporated by reference to Exhibit 10.82 to the Company's 1995
Form 10-K); Amendment No. 1 to the Amended and Restated
Employment Agreement between the Company and David L. Sokol,
dated August 28, 1996 (incorporated by reference to Exhibit 10.43
to the Company's 1996 Form 10-K), and Amendment No. 2 to the
Amended and Restated Employment Agreement between the Company and
David L. Sokol dated April 16, 1997 (incorporated by reference to
Exhibit 10.32 to the Company's 1997 Form 10-K).

10.4 * Restricted Stock Exchange Agreement between the Company and
David L. Sokol dated as of November 29, 1995 (incorporated by
reference to Exhibit 10.43 to the Company's 1995 Form 10-K),
Amendment No. 1 to the Restricted Stock Exchange Agreement
between the Company and David L. Sokol dated August 28, 1996 and
Amendment No. 2 dated April 16, 1997.

10.5 Employment Agreement between the Company and Gregory E.
Abel, dated August 6, 1996 (incorporated by reference to
Exhibit 10.44 to the Company's 1996 Form 10-K).

10.6 Amendment No. 1 to the Employment Agreement between the
Company and Gregory E. Abel dated April 16, 1997
(incorporated by reference to Exhibit 10.34 to the Company's
1997 Form 10-K).

10.7 Employment Agreement between the Company and Steven A.
McArthur, dated August 6, 1996 (incorporated by reference to
Exhibit 10.46 to the Company's 1996 Form 10-K).

10.8 Amendment No. 1 to the Employment Agreement between the
Company and Steven A. McArthur dated April 16, 1997
(incorporated by reference to Exhibit 10.38 to the Company's
1997 Form 10-K).

10.9 125 MW Power Plant - Upper Mahiao Agreement (the "Upper
Mahiao ECA") dated September 6, 1993 between PNOC-Energy
Development Corporation ("PNOC-EDC") and Ormat, Inc. as
amended by the First Amendment to 125 MW Power Plant Upper
Mahiao Agreement dated as of January 28, 1994, the Letter
Agreement dated February 10, 1994, the Letter Agreement
dated February 18, 1994 and the Fourth Amendment to 125 MW
Power Plant - Upper Mahiao Agreement dated as of March 7,
1994 (incorporated by reference to Exhibit 10.95 to the
Company's 1994 Form 10-K).

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

10.11 Credit Agreement dated as of April 8, 1994 between CE
Cebu Geothermal Power Company, Inc., Export-Import Bank of
the United States (incorporated by reference to Exhibit
10.97 to the Company's 1994 Form 10-K).
<PAGE>
10.12 Pledge Agreement among CE Philippines Ltd, Ormat-Cebu
Ltd., Credit Suisse as Collateral Agent and CE Cebu
Geothermal Power Company, Inc. dated as of April 8, 1994
(incorporated by reference to Exhibit 10.98 to the Company's
1994 Form 10-K).

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

10.14 180 MW Power Plant - Mahanagdong Agreement
("Mahanagdong ECA") dated September 18, 1993 between PNOC-
EDC and CE Philippines Ltd. and the Company, as amended by
the First Amendment to Mahanagdong ECA dated June 22, 1994,
the Letter Agreement dated July 12, 1994, the Letter
Agreement dated July 29, 1994, and the Fourth Amendment to
Mahanagdong ECA dated March 3, 1995 (incorporated by
reference to Exhibit 10.100 to the Company's 1994 Form 10-
K).

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

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

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

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

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

10.20 231 MW Power Plant - Malitbog Agreement ("Malitbog
ECA") dated September 10, 1993 between PNOC-EDC and Magma
Power Company and the First and Second Amendments thereto
dated December 8, 1993 and March 10, 1994, respectively
(incorporated by reference to Exhibit 10.106 to the
Company's 1994 Form 10-K).

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

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

10.23 Pledge and Security Agreement dated as of November 10,
1994 among Broad Street Contract Services, Inc., Magma Power
Company, Magma Netherlands B.V. and Credit Suisse as Bank
Agent (incorporated by reference to Exhibit 10.109 to the
Company's 1994 Form 10-K).
<PAGE>
10.24 Overseas Private Investment Corporation Contract of
Insurance dated December 21, 1994 between OPIC and Magma
Netherlands, B.V. (incorporated by reference to Exhibit
10.110 to the Company's 1994 Form 10-K).

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

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

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

10.28 Term Loan and Revolving Facility Agreement, dated as of
October 28, 1996, among CE Electric UK Holdings, CE Electric
UK plc and Credit Suisse (incorporated by reference to
Exhibit 10.130 to the Company's 1996 Form 10-K).

10.29 Public Electricity Supply License (incorporated by
reference to Exhibit 10.131 to the Company's 1996 Form 10-K)

10.30 Second Tier Supply Licenses to Supply Electricity for
England & Wales and Scotland (incorporated by reference to
Exhibit 10.132 to the Company's 1996 Form 10-K).

10.31 Pooling and Settlement Agreement for the Electricity
Industry in England and Wales dated 30th March, 1990 (as
amended at 17th October, 1996), among The Generators (named
therein), the Suppliers (named therein), Energy Settlements
and Information Services Limited (as Settlement System
Administrator), Energy Pool Funds Administration Limited (as
Pool Funds Administrator), Scottish Power plc, Electricite
deFrance, Service National and Others (incorporated by
reference to Exhibit 10.133 to the Company's 1996 Form 10-
K).

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

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

10.34 Acquisition Agreement by and between CalEnergy Company,
Inc. and Kiewit Diversified Group Inc. dated as of September
10, 1997 (incorporated by reference to Exhibit 2 to the
Company's Current Report on Form 8-K dated September 11,
1997).

10.35 Agreement and Plan of Merger dated as of August 11, 1998 by
and among CalEnergy Company, Inc., Maverick Reincorporation Sub,
Inc., MidAmerican Energy Holdings Company and MAVH Inc.
(incorporated by reference to the Company's Current Report on
Form 8-K dated August 11, 1998).

10.36 * Indenture and First Supplemental Indenture, dated March 11,
1999, between MidAmerican Funding LLC and IBJ Whitehall Bank &
Trust Company and the First Supplement thereto relating to the
$700 million Senior Notes and Bonds.
<PAGE>
10.37 * Settlement Agreement by and between MidAmerican Energy
Company, the Iowa Utilities Board, the Iowa Office of Consumer
Advocate, and others.

10.38 General Mortgage Indenture and Deed of Trust dated as
of January 1, 1993, between Midwest Power Systems Inc. and
Morgan Guaranty Trust Company of New York, Trustee. (Filed
as Exhibit 4(b)-1 to Midwest Resources Inc.'s Annual Report
on Form 10-K for the year ended December 31, 1992,
Commission File No. 1-10654.)

10.39 First Supplemental Indenture dated as of January 1,
1993, between Midwest Power Systems Inc. and Morgan Guaranty
Trust Company of New York, Trustee. (Filed as Exhibit 4(b)-
2 to Midwest Resources' Annual Report on Form 10-K for the
year ended December 31, 1992, Commission File No. 1-10654.)

10.40 Second Supplemental Indenture dated as of January 15,
1993, between Midwest Power Systems Inc. and Morgan Guaranty
Trust Company of New York, Trustee. (Filed as Exhibit 4(b)-
3 to Midwest Resources' Annual Report on Form 10-K for the
year ended December 31, 1992, Commission File No. 1-10654.)

10.41 Third Supplemental Indenture dated as of May 1, 1993,
between Midwest Power Systems Inc. and Morgan Guaranty Trust
Company of New York, Trustee. (Filed as Exhibit 4.4 to
Midwest Resources' Annual Report on Form 10-K for the year
ended December 31, 1993, Commission File No. 1-10654.)

10.42 Fourth Supplemental Indenture dated as of October 1,
1994, between Midwest Power Systems Inc. and Harris Trust
and Savings Bank, Trustee. (Filed as Exhibit 4.5 to Midwest
Resources' Annual Report on Form 10-K for the year ended
December 31, 1994, Commission File No. 1-10654.)

10.43 Fifth Supplemental Indenture dated as of November 1,
1994, between Midwest Power Systems Inc. and Harris Trust
and Savings Bank, Trustee. (Filed as Exhibit 4.6 to Midwest
Resources' Annual Report on Form 10-K for the year ended
December 31, 1994, Commission File No. 1-10654.)

10.44 Indenture of Mortgage and Deed of Trust, dated as of
March 1, 1947. (Filed by Iowa-Illinois Gas and Electric
Company ("Iowa-Illinois") as Exhibit 7B to Commission File
No. 2-6922.)

10.45 Sixth Supplemental Indenture dated as of July 1, 1967.
(Filed by Iowa-Illinois as Exhibit 2.08 to Commission File
No. 2-28806.)

10.46 Twentieth Supplemental Indenture dated as of May 1,
1982. (Filed as Exhibit 4.B.23 to Iowa-Illinois' Quarterly
Report on Form 10-Q for the period ended June 30, 1982,
Commission File No.
1-3573.)

10.47 Resignation and Appointment of successor Individual
Trustee. (Filed by Iowa-Illinois as Exhibit 4.B.30 to
Commission File No. 33-39211.)

10.48 Twenty-Eighth Supplemental Indenture dated as of May
15, 1992. (Filed as Exhibit 4.31.B to Iowa-Illinois'
Current Report on Form 8-K dated May 21, 1992, Commission
File No. 1-3573.)

10.49 Twenty-Ninth Supplemental Indenture dated as of March
15, 1993. (Filed as Exhibit 4.32.A to Iowa-Illinois'
Current Report on Form 8-K dated March 24, 1993, Commission
File No. 1-3573.)

10.50 Thirtieth Supplemental Indenture dated as of October 1,
1993. (Filed as Exhibit 4.34.A to Iowa-Illinois' Current
Report on Form 8-K dated October 7, 1993, Commission File
No. 1-3573.)
<PAGE>
10.51 Sixth Supplemental Indenture dated as of July 1, 1995,
between Midwest Power Systems Inc. and Harris Trust and Savings
Bank, Trustee. (Filed as Exhibit 4.15 to MidAmerican Energy
Company's ("MidAmerican Energy") Annual Report on Form 10-K dated
December 31, 1995, Commission File No. 1-11505.)

10.52 Thirty-First Supplemental Indenture dated as of July 1,
1995, between Iowa-Illinois Gas and Electric Company and
Harris Trust and Savings Bank, Trustee. (Filed as Exhibit
4.16 to MidAmerican Energy's Annual Report on Form 10-K
dated December 31, 1995, Commission File No. 1-11505.)

10.53 Power Sales Contract between Iowa Power Inc. and
Nebraska Public Power District, dated September 22, 1967. (Filed
as Exhibit 4-C-2 to Iowa Power Inc.'s (IPR) Registration
Statement, Registration No. 2-27681).

10.54 Amendments Nos. 1 and 2 to Power Sales Contract between
Iowa Power Inc. and Nebraska Public Power District. (Filed as
Exhibit 4-C-2a to IPR's Registration Statement, Registration No.
2-35624.)

10.55 Amendment No. 3 dated August 31, 1970, to the Power
Sales Contract between Iowa Power Inc. and Nebraska Public Power
District, dated September 22, 1967. (Filed as Exhibit 5-C-2-b to
IPR's Registration Statement, Registration No. 2-42191.)

10.56 Amendment No. 4 dated March 28, 1974, to the Power
Sales Contract between Iowa Power Inc. and Nebraska Public Power
District, dated September 22, 1967. (Filed as Exhibit 5-C-2-c to
IPR's Registration Statement, Registration No. 2-51540.)

10.57 Amendment No. 5 dated September 2, 1997, to the Power
Sales Contract between MidAmerican Energy Company and Nebraska
Public Power District, dated September 22, 1967. (Filed as
Exhibit 10.2 to MidAmerican Energy's Quarterly Reports on the
combined Form 10-Q for the quarter ended September 30, 1997,
Commission File Nos. 1-12459 and 1-11505, respectively.)

10.58 MidAmerican Energy Company Severance Plan For Specified
Officers dated November 1, 1996. (Filed as Exhibit 10.1 to
MidAmerican Energy's Annual Reports on the combined Form 10-K for
the year ended December 31, 1996, Commission File Nos. 1-12459
and 1-11505, respectively.)

10.59 MidAmerican Energy Company Deferred Compensation Plan
for Executives. (Filed as Exhibit 10.2 to MidAmerican Energy's
Annual Report on Form 10-K dated December 31, 1995, Commission
File No. 1-11505.)

10.60 MidAmerican Energy Company Supplemental Retirement Plan
for Designated Officers. (Filed as Exhibit 10.3 to
MidAmerican Energy's Annual Report on Form 10-K dated December
31, 1995, Commission File No. 1-11505.)

10.61 MidAmerican Energy Company Key Employee Short-Term
Incentive Plan. (Filed as Exhibit 10.4 to MidAmerican's Annual
Report on Form 10-K dated December 31, 1995, Commission File No.
1-11505.)

10.62 Deferred Compensation Plan for Executives of Midwest
Resources Inc. and Subsidiaries. (Filed as Exhibit 10.1 to
Midwest Resources' Annual Report on Form 10-K for the year ended
December 31, 1990, Commission File No. 1-10654).

10.63 Deferred Compensation Plan for Board of Directors of
Midwest Resources Inc. and Subsidiaries. (Filed as Exhibit 10.2
to Midwest Resources' Annual Report on Form 10-K for the year
ended December 31, 1990, Commission File No. 1-10654).
<PAGE>
10.64 Midwest Resources Inc. revised and amended Executive
Deferred Compensation Plan for IOR and Subsidiaries, dated
January 29, 1992. (Filed as Exhibit 10.5 to Midwest Resources'
Annual Report on Form 10-K for the year ended December 31, 1991,
Commission File No. 1-10654.)

10.65 Midwest Resources Inc. revised and amended Board of
Directors Deferred Compensation Plan for IOR and Subsidiaries,
dated January 29, 1992. (Filed as Exhibit 10.6 to Midwest
Resources' Annual Report on Form 10-K for the year ended December
31, 1991, Commission File No. 1-10654.)

10.66 Midwest Resources Inc. Supplemental Retirement Plan
(formerly the Midwest Energy Company Supplemental Retirement
Plan). (Filed as Exhibit 10.10 to Midwest Resources' Annual
Report on Form 10-K for the year ended December 31, 1993,
Commission File No. 1-10654.)

10.67 Revised and amended Executive Deferred Compensation
Plan for IPR and Subsidiaries, dated July 24, 1985. (Filed as
Exhibit 10.22 to IPR's Annual Report on Form 10-K for the year
ended December 31, 1985, Commission File No. 1-7830.)

10.68 Revised and amended Deferred Compensation Plan for
Board of Directors of IPR and Subsidiaries, dated July 24, 1985.
(Filed as Exhibit 10.22 to IPR's Annual Report on Form 10-K for
the year ended December 31, 1985, Commission File No. 1-7830.)

10.69 Revised and amended Executive Deferred Compensation
Plan for IPR and Subsidiaries, dated December 18, 1987. (Filed
as Exhibit 10.15 to IPR's Annual Report on Form 10-K for the year
ended December 31, 1987, Commission File No. 1-7830.)

10.70 Revised and amended Deferred Compensation Plan for
Board of Directors of IPR and Subsidiaries, dated December 18,
1987. (Filed as Exhibit 10.16 to IPR's Annual Report on Form 10-
K for the year ended December 31, 1987, Commission File No. 1-
7830.)

10.71 Amendments to Midwest Resources Executive Deferred
Compensation Plans, dated October 30, 1992. (Filed as Exhibit
10(h) to Midwest Resource's Annual Report on Form 10-K for the
year ended December 31, 1992, Commission File No. 1-10654.)

10.72 Supplemental Retirement Plan for Principal Officers, as
amended as of July 1, 1993. (Filed as Exhibit 10.K.2 to Iowa-
Illinois' Annual Report on Form 10-K for the year ended December
31, 1993, Commission File No. 1-3573.)

10.73 Compensation Deferral Plan for Principal Officers, as
amended as of July 1, 1993. (Filed as Exhibit 10.K.2 to Iowa-
Illinois' Annual Report on Form 10-K for the year ended December
31, 1993, Commission File No. 1-3573.)

10.74 Board of Directors' Compensation Deferral Plan. (Filed
as Exhibit 10.K.4 to Iowa-Illinois' Annual Report on Form 10-K
for the year ended December 31, 1992, Commission File No. 1-
3573.)

10.75 Amendment No. 1 to the Midwest Resources Inc.
Supplemental Retirement Plan. (Filed as Exhibit 10.24 to Midwest
Resources' Annual Report on Form 10-K for the year ended December
31, 1994, Commission File No. 1-10654.)

10.76 Deferred Compensation Plan of Midwest Energy Company
and Subsidiary Corporations. (Filed as Exhibit 10.25 to Midwest
Resources' Annual Report on Form 10-K for the year ended December
31, 1994, Commission File No. 1-10654.)

10.77 MidAmerican Energy Company 1995 Long-Term Incentive
Plan. (Filed as Exhibit 10(a) to MidAmerican Energy Holding
Company's (now known as MHC, Inc.) Registration Statement on Form
S-4, File No. 333-01645.)
<PAGE>
10.78 Amendment No. 5 dated September 2, 1997, to the Power
Sales contract between MidAmerican Energy Company and Nebraska
Public Power District, dated September 22, 1967. (Filed as
Exhibit 10.2 to MidAmerican Energy's Quarterly Reports on the
combined Form 10-Q for the quarter ended September 30, 1997,
Commission File Nos. 1-12459 and 1-11505, respectively.)

10.79 Amendment No. 1 dated October 29, 1997, to the
MidAmerican Energy Company 1995 Long-Term Incentive Plan. (Filed
as Exhibit 10.1 to MidAmerican Energy's Quarterly Reports on the
combined Form 10-Q for the quarter ended September 30, 1997,
Commission File Nos. 1-12459 and 1-11505, respectively.)

13.0 The Company's 1998 Annual Report (only the portions thereof
specifically incorporated herein by reference are deemed
filed herewith).

21.0 * Subsidiaries of Registrant.

23.0 Consent of Independent Auditors.

24.0 Power of Attorney.

27.0 Financial Data Schedule.

*To be filed by amendment.
<PAGE>
MidAmerican Energy Holdings Company Schedule I
Parent Company Only
Condensed Balance Sheets
as of December 31, 1998 and 1997
(dollars and shares in thousands, except per share amounts)

1998 1997

ASSETS
Cash and cash equivalents $ 1,522,294 $ 1,280,477
Investments in and advances to subsidiaries
and joint ventures 2,442,118 1,932,912
Equipment, net 17,554 19,016
Deferred charges and other assets 155,332 105,223

Total assets $ 4,137,298 $ 3,337,628

LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable and other accrued liabilities $ 98,940 $ 46,964
Parent company debt 2,645,991 1,303,845
Total liabilities 2,744,931 1,350,809

Deferred income 11,384 12,827
Company-obligated mandatorily redeemable
convertible preferred securities of subsidiary trusts 553,930 553,930
Common stock and options subject to redemption --- 654,736

Stockholders' equity:
Preferred stock - authorized 2,000 shares, no par value --- ---
Common stock - par value $0.0675 per share,
authorized 180,000 shares, issued 82,980 shares,
outstanding 59,605 and 81,322 shares, respectively 5,602 5,602
Additional paid in capital 1,233,088 1,261,081
Retained earnings 340,496 213,493
Accumulated other comprehensive income 45 (3,589)
Common stock and options subject to redemption --- (654,736)
Treasury stock- 23,375 and 1,658 common shares
at cost (752,178) (56,525)
Total stockholders' equity 827,053 765,326
Total liabilities and stockholders' equity $4,137,298 $3,337,628

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

<PAGE>
MidAmerican Energy Holdings Company Schedule I
Parent Company Only (continued)
Condensed Statements Of Operations
for the three years ended December 31, 1998
(dollars in thousands)
1998 1997 1996

Revenue:

Equity in undistributed earnings of subsidiary
companies and joint ventures $ 205,049 $ 79,905 $ 85,535
Cash dividends and distributions from subsidiary
companies and joint ventures 179,782 156,686 102,428
Interest and other income 44,686 49,488 22,459

Total revenues 429,517 286,079 210,422

Expenses:

General and administration 30,527 36,616 15,170
Interest, net of capitalized interest 132,250 75,438 56,279

Total expenses 162,777 112,054 71,449

Income before provision for income taxes 266,740 174,025 138,973
Provision for income taxes 93,265 99,044 41,821

Income before minority interest 173,475 74,981 97,152
Minority interest 35,963 23,158 4,691

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

Income per share before extraordinary item and cumulative
effect of change in accounting principle $ 2.29 $ .77 $ 1.69
Extraordinary item ( .12) (2.02) ---
Cumulative effect of change in accounting
principle ( .06) --- ---
Net income (loss) per share $ 2.11 $ (1.25) $ 1.69

Income per share before extraordinary item
and cumulative effect of change in
accounting principle - diluted $ 2.15 $ .75 $ 1 .54
Extraordinary item - diluted ( .10) (1.97) ---
Cumulative effect of change in accounting principle
-diluted ( .04) --- ---
Net income (loss) per share - diluted $ 2.01 $ (1.22)$ 1.54

Average number of shares outstanding 60,139 67,268 54,739
Diluted shares 74,100 68,686 65,072

The notes to the consolidated MidAmerican financial
statements are an integral part of these financial
statements.
<PAGE>
MidAmerican Energy Holdings Company Schedule I
Parent Company Only (continued)
Condensed Statements Of Cash Flows
for the three years ended December 31, 1998
(dollars in thousands)
1998 1997 1996

Cash flows from operating activities $(219,705) $(200,057) $(38,961)

Cash flows from investing activities:
Decrease (increase) in advances to and
investments in subsidiaries and
joint ventures (103,494) 174,584 (524,647)
Decrease (increase) in short-term investments 421 (229) 33,998
Other (24,749) 18,330 (5,179)

Cash flows from investing activities (127,822) 192,685 (495,828)

Cash flows from financing activities:
Proceeds from sale of common and treasury stock and
exercise of stock options 3,412 703,624 54,935
Proceeds from issuance of parent
company debt 1,502,243 350,000 324,150
Proceeds from convertible preferred securities
of subsidiary trusts --- 450,000 103,930
Repayment of parent company debt (167,285) (100,000) ---
Net proceeds from revolver --- (95,000) 95,000
Purchase of treasury stock (724,791) (55,505) (12,008)
Deferred charges relating to debt financing (24,235) (33,719) (8,811)

Cash flows from financing activities 589,344 1,219,400 557,196

Net increase in cash and cash equivalents 241,817 1,212,028 22,407

Cash and cash equivalents at beginning
of period 1,280,477 68,449 46,042

Cash and cash equivalents at end of period $1,522,294 $1,280,477 $ 68,449

Supplemental disclosures:
Interest paid (net of amount
capitalized) $ 104,350 $ 38,176 $ 1,705

Income taxes paid $ 32,100 $ 35,302 $ 23,211

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

<PAGE>

INDEPENDENT AUDITORS' REPORT

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

We have audited the consolidated financial statements of
MidAmerican Energy Holdings Company, the successor of
CalEnergy Company, Inc. and subsidiaries' as of December 31,
1998 and 1997, and for each of the three years in the period
ended December 31, 1998, and have issued our report thereon
dated January 28, 1999 (March 12, 1999 as to Note 3 and Note
21); such financial statements and reports are included in
your 1998 Annual Report to Stockholders and are incorporated
herein by reference. Our audits also included the financial
statement schedule of MidAmerican Energy Holdings Company
and subsidiaries, listed in Item 14. This financial
statement schedule is the responsibility of the Company's
management. Our responsibility is to express an opinion
based on our audits. In our opinion, such financial
statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in
all material respects the information set forth therein.

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

Financial Summary EXHIBIT 13

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

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

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

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

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

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

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

Acquisitions

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

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

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

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

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

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

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

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

1998 1997 1996

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

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

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

1998 1997 1996

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

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

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

1998 1997 1996

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Liquidity and Capital Resources

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Recent Accounting Pronouncements

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

Qualitative and Quantitative Disclosures About Market Risk

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

Interest Rate Risk

At December 31, 1998, the Company had fixed-rate long-term debt
and Company-obligated mandatorily redeemable convertible
preferred securities of subsidiary trusts of $5,712.3 million in
principal amount and having a fair value of $6,049.9 million.
These instruments are fixed-rate and therefore do not expose the
Company to the risk of earnings loss due to changes in market
interest rates. However, the fair value of these instruments
would decrease by approximately $265 million if interest rates
were to increase by 10% from their levels at December 31, 1998.
In general, such a decrease in fair value would impact earnings
and cash flows only if the Company were to reacquire all or a
portion of these instruments prior to their maturity.

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

Currency Exchange Rate Risk

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

Energy Commodity Price Risk

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

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

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

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

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

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

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

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

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

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

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

ASSETS 1998 1997

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

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

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

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

Deferred income 58,468 40,837

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

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

Total stockholders' equity 827,053 765,326

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

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

1998 1997 1996

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

* Foreign currency translation adjustment has no tax effect

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

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

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

1. Business

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

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

2. Summary of Significant Accounting Policies

The consolidated financial statements include the accounts of the
Company, its wholly-owned subsidiaries, and its proportionate
share of the partnerships and joint ventures in which it has an
undivided interest in the assets and is proportionally liable for
its share of liabilities. Other investments and corporate joint
ventures where the Company has the ability to exercise significant
influence are accounted for under the equity method of accounting.
Investments, where the Company's ability to influence is limited,
are accounted for under the cost method of accounting. All
significant inter-enterprise transactions and accounts have been
eliminated. The results of operations of the Company include the
Company's proportionate share of results of operations of entities
acquired as of the date of each acquisition.

Cash Equivalents, Investments and Restricted Cash

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

Investments other than restricted cash are primarily commercial
paper and money market securities. The restricted cash balance
includes such securities and mortgage backed securities, and is
mainly composed of amounts deposited in restricted accounts from
which the Company will source its equity contributions and debt
service reserve requirements relating to the projects. These
funds are restricted by their respective project debt agreements
to be used only for the related project.

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

Properties, Plants, Contracts, Equipment and Depreciation

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

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

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

Property and equipment of Northern is depreciated using
a systematic method, which approximates the straight
line method over the estimated useful lives of the
related assets which range from 3-60 years.

Power sales agreements are amortized separately over (1)
the remaining portion of the scheduled price periods of
the power sales agreements and (2) for the Partnership
Interest and Magma acquisitions the 20 year avoided cost
periods of the power sales agreements using the straight
line method.

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

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

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

Well, Resource Development and Exploration Costs

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

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

Impairment of Long-Lived Assets

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

Deferred Well and Rework Costs

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

Revenue Recognition

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

Capitalization of Interest and Deferred Financing Costs

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

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

Deferred Income Taxes

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

Pensions

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

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

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

Financial Instruments

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

Foreign Currency Translation

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

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

Reclassification

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

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

New Accounting Pronouncement

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

3. MidAmerican Merger

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

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

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

4. Acquisitions

KDG

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

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

$1,160,215

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

Northern

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

Falcon Seaboard

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

Edison Mission Energy's Partnership Interest

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

5.Properties, Plants, Contracts and Equipment

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

1998 1997

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

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

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

Coso Project Operating Facilities

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

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

Imperial Valley Project Operating Facilities

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

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

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

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

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

Significant Customers and Contracts

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

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

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

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

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

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

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

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

Philippine Projects

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

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

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

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

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

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

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

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

Roosevelt Hot Springs

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

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

Salton Sea Minerals Extraction

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

6. Equity Investments

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

Saranac NorCon

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

7. Parent Company Debt

Parent company debt comprises the following at December 31:

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

Senior Discount Notes

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

9.5% Senior Notes

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

7.63% Senior Notes

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

Limited Recourse Senior Secured Notes

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

$1.4 Billion Senior Notes

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

$100 Million Senior Notes

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

Revolving Credit Facility

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

8. Subsidiary and Project Debt

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

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

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

Salton Sea Notes and Bonds

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

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

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

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

Northern Eurobonds

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

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

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

CE Electric UK Funding Company Senior Notes and Sterling Bonds

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

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

Power Resources Project Financing Debt

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

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

Coso Funding Corp. Project Loans

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

Casecnan Notes and Bonds

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

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

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

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

Upper Mahiao Loans

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

Mahanagdong Loans

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

Northern Short Term Treasury Loan

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

CE Gas Loan

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

Annual Repayments of Subsidiary and Project Debt

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

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

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

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

9. Income Taxes

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

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

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

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

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

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

Net deferred taxes $543,391 $509,059

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

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

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

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

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

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

Pursuant to Preferred Securities Guarantee Agreements
(collectively, the "Guarantees"), between the Company and a
preferred guarantee trustee, the Company has agreed irrevocably to
pay to the holders of the Trust Securities, to the extent that the
Trustee has funds available to make such payments, quarterly
distributions, redemption payments and liquidation payments on the
<PAGE>
Trust Securities. Considered together, the undertakings contained
in the Declarations, Junior Debentures, Indentures and Guarantees
constitute full and unconditional guarantees by the Company of the
Trusts' obligations under the Trust Securities.

11.Preferred Stock

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

12.Stock Options and Restricted Stock

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

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

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

Transactions in Stock Options

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

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

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

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

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

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

13. Equity Offering

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

14. Asset Valuation Impairment Charge

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

15. Extraordinary Item

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

16.Fair Value of Financial Instruments

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

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

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

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

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

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

17. Regulatory Matters

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

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

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

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

18. Pension Commitments

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

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

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

1998 1997

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

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

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

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

19. Commitments and Contingencies

Indonesia

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

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

NYSEG

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

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

20. Segment Information

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

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

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

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

21. Subsequent Events

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

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

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

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

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

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

<PAGE>
22. QUARTERLY FINANCIAL DATA (UNAUDITED)

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

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

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

INDEPENDENT AUDITORS' REPORT

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

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

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

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

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

Exhibit 23

INDEPENDENT AUDITORS' CONSENT

We consent to the incorporation by reference in Registration
Statement No. 33-38431, No. 33-41152, No. 33-44934, No. 33-
52147, No. 33-64897 and No. 333-30395 on Form S-8 and
Registration Statement No. 33-51363, No. 333-32821 and No.
333-62697 on Form S-3 of MidAmerican Energy Holdings Company
(the successor to CalEnergy Company, Inc.) of our reports
dated January 28, 1999 (March 12, 1999 as to Note 3 and Note
21), appearing in and incorporated by reference in the
Annual Report on Form 10-K of MidAmerican Energy Holdings
Company for the year ended December 31, 1998.

DELOITTE & TOUCHE L.L.P.

Omaha, Nebraska
March 30, 1999

Exhibit 24

POWER OF ATTORNEY

The undersigned, a member of the Board of Directors or

officer of MidAmerican Energy Holdings Company, an Iowa

corporation (the "Company"), hereby constitutes and appoints

Steven A. McArthur and Douglas L. Anderson and each of them,

as his/her true and lawful attorney-in-fact and agent, with

full power of substitution and resubstitution, for and in

his/her stead, in any and all capacities, to sign on his/her

behalf the Company's Form 10-K Annual Report for the fiscal

year ending December 31, 1998 and to execute any amendments

thereto and to file the same, with all exhibits thereto, and

all other documents in connection therewith, with the

Securities and Exchange Commission and applicable stock

exchanges, with the full power and authority to do and

perform each and every act and thing necessary or advisable

to all intents and purposes as he/she might or could do in

person, hereby ratifying and confirming all that said

attorney-in-fact and agent, or his/her substitute or

substitutes, may lawfully do or cause to be done by virtue

hereof.

POWER OF ATTORNEY

Executed as of March 29, 1999

______________________________
______________________________
DAVID L. SOKOL RICHARD R. JAROS

______________________________
______________________________
GREGORY E. ABEL DAVID R. MORRIS

______________________________
______________________________
ALAN L. WELLS JOHN R. SHINER

______________________________
______________________________
PATRICK J. GOODMAN BERNARD W. REZNICEK

______________________________
______________________________
EDGAR D. ARONSON WALTER SCOTT, JR.

______________________________
______________________________
JUDITH E. AYRES DAVID E. WIT

<ARTICLE> 5
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 2,121,379
<SECURITIES> 122,340
<RECEIVABLES> 528,116
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 0
<PP&E> 5,005,565
<DEPRECIATION> 769,526
<TOTAL-ASSETS> 9,103,524
<CURRENT-LIABILITIES> 0
<BONDS> 5,739,801
553,930
66,033
<COMMON> 5,602
<OTHER-SE> 821,451
<TOTAL-LIABILITY-AND-EQUITY> 9,103,524
<SALES> 2,555,206
<TOTAL-REVENUES> 2,682,711
<CGS> 1,258,539
<TOTAL-COSTS> 425,004
<OTHER-EXPENSES> 46,401
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 347,292
<INCOME-PRETAX> 272,053
<INCOME-TAX> 93,265
<INCOME-CONTINUING> 137,850
<DISCONTINUED> 0
<EXTRAORDINARY> (7,146)
<CHANGES> (3,363)
<NET-INCOME> 127,003
<EPS-PRIMARY> 2.11
<EPS-DILUTED> 2.01

</TABLE>