MIDAMERICAN ENERGY HOLDINGS CO /NEW/, 10-K405, 2000-03-30

MIDAMERICAN ENERGY HOLDINGS CO /NEW/
10-K405, 2000-03-30
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, 1999
Commission File No. 0-25551

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

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

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

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

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

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

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

Yes X No
-----

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

All of the shares of MidAmerican Energy Holdings Company are held by a limited
group of private investors. As of March 30, 2000, 9,281,087 shares of common
stock were outstanding.

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TABLE OF CONTENTS

-----------------

PART I........................................................................4
Item 1. Business.............................................................4
General.......................................................................4
Berkshire Transaction.........................................................4
Strategy......................................................................4
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.....................................................14
The Company's Power Generation Project Portfolio.............................15
Projects in Operation........................................................17
United States Power Generation........................................17
MidAmerican Energy Generation Facilities..............................17
CE Generation Geothermal Facilities...................................18
CE Generation Gas Facilities..........................................20
Other U.S. Geothermal Interests.......................................21
United Kingdom Power Generation.......................................21
The Philippines Power Generation......................................22
Projects in Construction.....................................................24
United States.........................................................24
Philippines...........................................................25
United Kingdom........................................................26
Projects in Development.......................................................26
United States.........................................................26
United Kingdom........................................................27
Producing Gas Field Operations and Fields in Development.....................27
Producing Fields......................................................27
Projects in Development...............................................27
Other ......................................................................29
HomeServices..........................................................29
Indonesia.............................................................29
Regulatory, Energy and Environmental Matters.................................30
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.............................................34
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations...........................................34
Item 7A. Qualitative and Quantitative Disclosures About Market Risk..........34
Item 8. Financial Statements and Supplementary Data.........................34
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................................34

PART III.....................................................................35
Management...................................................................35

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Item 10. Directors, Executive and Other Officers of the
Company and Significant Subsidiaries......................... ......35
Item 11. Executive Compensation..............................................40
Item 12. Security Ownership of Certain Beneficial Owners and Management......40
Item 13. Certain Relationships and Related Transactions......................40

PART IV......................................................................41
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....41

SIGNATURES..................................................................100

EXHIBIT INDEX...............................................................102

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PART I

ITEM 1. BUSINESS

General
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MidAmerican Energy Holdings Company (the "Company" or "MEHC"), is a United
States based privately owned global energy company with publicly traded fixed
income securities. Through its subsidiaries, the Company manages, owns interests
in and has under contract approximately 9,700 megawatts ("MW") of diversified
power generation facilities in operation, construction and development. In
addition, through its subsidiaries, MidAmerican Energy Company ("MidAmerican
Energy" or "MEC") and Northern Electric plc ("Northern"), the Company currently
serves approximately 2.0 million electricity customers and 1.2 million natural
gas customers worldwide. 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).

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 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.

Berkshire Transaction
- ---------------------

On October 24, 1999, the Company entered into an Agreement and Plan of Merger
with an investor group that included Berkshire Hathaway Inc., Walter Scott, Jr.,
and David L. Sokol (the "Investor Group"). The Investor Group closed on the
acquisition on March 14, 2000. Pursuant to the acquisition, the Investor Group
paid the Company's shareholders $35.05 in cash for each outstanding share of the
Company's common stock and became the sole shareholders of the Company in a
"going private" transaction.

Strategy
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The Company's strategy remains focused on profit enhancement through operating
efficiencies while maintaining quality and reliability of service and continued
diversification of its assets by taking advantage of the investment opportuni-
ties created by the continuing restructuring and privatization in energy sectors
in the United States and throughout the world. In order to effectively execute
its strategy, the Company has organized its operations into a functional
structure. The functional alignment is believed to allow for greater effi-
ciencies in operations and better coordination and asset utilization in devel-
oping the Company's business.

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

o 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 2.6 cents/kWh in 1999. The Company has achieved these efficien-
cies 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.

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<PAGE>

o Continued Diversification of Revenue Base and Fuel Sources. The Com-
pany believes that it has a diversified revenue base, distributed among
its ownership of two operating electricity and gas utilities, its
ownership of interests in diversified power generation facilities with
10,260 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, which are
largely derived from the generation, transmission, distribution and
sale of electricity and the distribution and sale of gas activities,
and Northern, which are largely derived from their electricity distri-
bution and gas supply activities, a portion of the Company's revenues
are from its 50% equity ownership interest in CE Generation, throug
long-term contracts between project subsidiaries and four 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 revenu
base and fuel sources through acquisitions and greenfield development.

o Growth through International and Domestic Acquisitions. The Company
intends to continue to opportunistically engage in international and
domestic acquisitions of energy projects and companies that support it
long term investment strategy.

The Company further believes that the electricity and gas industry in
the U.S. will progressively restructure over the next three to five
years and will largely follow the deregulatory 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 pro-
fitability in a price competitive market, the Company believes that
opportunities will become available to acquire low cost and reliabl
providers of energy services to gain market share in energy supply and
provide additional services to competitors (such as utility line con-
struction and maintenance services, metering, customer billing and
information systems services).

o Growth through Greenfield Development of Energy Projects. The Company
has commenced construction of a 537 MW natural gas fired generation
facility which will sell power on a partial contract and partial
merchant basis. The facility is located near the Quad Cities in Illi-
nois and Iowa on the border of two electric reliability districts, the
Mid-Continent. Area Power Pool and the Mid-America Interconnection
Network. In addition to developing domestic energy projects, 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. With CalEnergy Gas (UK)Limited, the Company has expanded its
development strategy to include integrated upstream natural gas opera-
tions. 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.

o Maintenance of Prudent Financial and Risk Management Practices. The
Company has consistently maintained, and intends in the future to main-
tain 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 Genera-
tion LLC is rated Baa3, BBB and BBB-; its Northern Electric subsidiary
is rated A3, A and A-, and its CE Electric UK Funding Company subsidi-
ary's senior notes are rated Baa1, A- and BBB+. 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 fin-
ancing structures utilized to date by the Company include as a funda-
mental protection for the Company's other assets the requirement that
(with certain minimal exceptions) the funds borrowed and other obliga-
tions for the purpose of financing or operating a project are to be
primarily or entirely under loan agreements, project agreements and
related
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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 project
in a manner which minimizes the exposure of the Company's other assets
through appropriate non-recourse project structures.

o 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 overed by insurance. The Company's international invest-
ment criteria generally includes giving due consideration, where
appropriate, to the following:
o Sovereign guarantees;
o Significant demand for new power generating facilities;
o An established legal system providing for enforceability of
con- tracts and regulations;
o "Take or Pay" contracts with utilities, governments or other
parties with acceptable creditworthiness which provide for
pri- marily US$-denominated payments and certain contractual
protec- tions regarding currency convertibility and
transferability;
o Fixed-price date-certain, turnkey construction contracts
with liquidated damages and performance security provisions;
and
o 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 is a global competitive market as many countries have initiated
restructuring and privatization policies that encourage the development of
independent power generation and independent distribution and supply of energy.
The movement toward privatization in some developing countries has created new
markets. The need for 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 intends to evaluate opportunities in these markets and to develop,
construct and acquire power generation, distribution and supply and related
energy projects meeting its strategic criteria both inside and outside the
United States. In addition, as privatization, deregulation and restructuring
initiatives are enacted in various countries and states, the Company will
evaluate opportunities to acquire power generation, distribution and supply
assets, as well as other energy related infrastructure assets.

In pursuing its strategy, the Company presently intends to focus upon
development and acquisition opportunities in countries possessing
characteristics that 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. 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

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

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<PAGE>

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, in which the
Company has several power production facilities, 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. Approximately one-half of the
states have enacted electric choice legislation and 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.

In that regard, in December 1999, the Federal Energy Regulatory Commission
issued Order No. 2000 establishing, among other things, minimum characteristics
and functions for Regional Transmission Organizations (RTOs). Public utilities
not a member of an independent system operator at the time of the order are
required to submit a plan by which its transmission facilities would be
transferred to an RTO on a schedule that would allow the RTO to commence
operating by December 15, 2001. MidAmerican Energy, which was not a member of an
independent system operator, is presently analyzing the impact that the order
may have on its operations.

In Illinois, the electric retail business is opening up to competition and will
be phased in between October 1999 and May 2002. In Iowa, legislation that would
restructure the electric utility business is being considered by the legislature
during its 2000 session.

MidAmerican Energy is subject to comprehensive regulation by several utility
regulatory agencies that 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 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 Energy'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 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 was allowed to recover its energy
costs from most of its electric utility customers through energy adjustment
clauses. Beginning in July 1997, the Iowa energy adjustment clause was
eliminated as part of the Iowa pricing plan approved by the Iowa Utilities
Board. Accordingly, flucuations in energy costs now may affect MidAmerican
Energy's earnings.

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MidAmerican Energy provides gas service at retail pursuant to non- exclusive
municipal franchises. The cost of gas is recovered from customers through a
purchased gas adjustment clause.

In connection with the March 1999 approval by the Iowa Utilities Board of the
MidAmerican Merger and recent affirmation as part of the Investor Group's
acquisition of the Company, MidAmerican Energy is required, among other things,
to use all commercially reasonable efforts to maintain an investment grad 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 circum- stances.
MidAmerican Energy's common equity level at December 31, 1999 was above these
levels.

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 discon- tinued
applicability f 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, Eastern Electricity 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. The majority of
customers are supplied with electricity by their local REC, although there are
other suppliers holding second tier supply licenses, including 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 through a phased-in program. This program, which proceeded
by geographic areas, was completed in 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 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 inflation factor ("Xd") which was established by the Regulator (and
continues to be set) at 3%. 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

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from year to year. It is a control on revenue which operates independently of
the REC's costs. During the lifetime of the price control additional cost
savings therefore contribute directly to profit.

In connection with the scheduled distribution price control review concluded by
the Regulator in 1999, Northern's allowable distribution revenue is to be
reduced by 24% with effect from April 1, 2000. As part of the review, the Xd
factor was not modified and therefore remains at 3%.

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 in 2005. The formula may be further
reviewed at other times in the discretion of the Regulator, including in the
next several years in connection with certain government proposed regulatory
incentive initiatives.

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: public electricity supply ('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 price of electricity supplied by a PES to most of its domestic customers
within its authorized area is controlled by a formula. As part of the scheduled
review of the formula carried out by the Regulator in 1999, Northern will be
required to reduce its prices to most of its domestic customers within its
authorized area by about 11% from April 1, 2000.

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 supply 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.

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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 varies, 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 and the
introduction of the New Electricity Trading Arrangements ("NETA") is October 31,
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, 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.

Under NETA, suppliers will need to buy physical electricity from generators
equal to the forecast demand of customers. NETA will create additional risks and
opportunities and in order to mitigate them, Northern is developing a new suite
of information technology systems in coordination with industry leading software
development companies.

The UK government has recently introduced into Parliament legislation which, if
enacted, will facilitate certain aspects of the reform of the wholesale
electricity trading market described above, and reform UK utility law in
connection with the licensing regime for electricity and gas utilities,
electricity and gas regulatory institutions and procedures, and social, consumer
and environmental protection related to utilities.

The Company's Distribution and Supply Business

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MidAmerican Energy Company

MidAmerican Energy is the largest energy company headquartered in Iowa, with
assets and 1999 revenues totaling $3.6 billion and $1.8 billion, respectively.
MidAmerican Energy 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 Iowa, Illinois and South Dakota. It also distributes natural gas at
retail in Iowa, Illinois, South Dakota and Nebraska. As of December 31, 1999,
MidAmerican Energy had 663,500 retail electric customers and 638,000 retail
natural gas customers.

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

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

MidAmerican Energy has a residential, agricultural, commercial and diversified
industrial customer group, in which no single industry or customer accounted for
more than 5% of its total 1999 electric operating revenues or 3% of its total
1999 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.

For the year ended December 31, 1999, MidAmerican Energy derived approximately
66% of its gross operating revenues from its regulated electric business, and
25% from its regulated gas business and 9% from its nonregulated business
activities. For 1998 and 1997, the corresponding percentages were 69% electric,
25% gas and 6% nonregulated; and 65% electric and 31% gas and 4% nonregulated,
respectively.

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

A substantial majority of MidAmerican Energy'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. MidAmerican Energy also manages its operations as four distinct
business units: generation, transmission, energy distribution and retail. It is
under this framework that MidAmerican Energy believes it can best prepare for,
and succeed in, the energy business of the future. 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 that supports all of the
business units.

Although specific functions may be moved between business units as future
circumstances warrant, the main 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

1999 1998 1997

Residential 21.0% 22.2% 20.9%
Small General Service 16.7 17.5 16.5
Large General Service 26.9 28.1 27.4
Other 4.5 4.4 4.4
Sales for Resale 30.9 27.8 30.8
----- ----- -----
Total 100.0% 100.0% 100.0%
===== ===== =====

-11-
<PAGE>

Retail Electric Sales of MidAmerican Energy By State

1999 1998 1997

Iowa 88.9% 88.4% 88.6%
Illinois 10.4 10.9 10.7
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 electric
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. The 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 incurs to fulfill
these contracts will vary. On an aggregate basis, the annual revenues under
these contracts are approximately $180 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 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%.

Under a restructuring law enacted in 1997, a similar sharing mechanism is in
place for Illinois operations. Two-year average returns on common equity greater
than a two year average benchmark will trigger an equal sharing of earnings on
the excess. The benchmark is a calculation of average 30-year Treasury Bond
rates plus 5.5% for 1998 and 1999 and 8.5% for 2000 through 2004. The initial
calculation, due March 31, 2000, will be based on 1998 and 1999 results.

In Illinois beginning October 1, 1999, larger non-residential customers and 33%
of the remaining non-residential customers are 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:

-12-
<PAGE>

Total Regulated Gas Sales of MidAmerican Energy By Customer Class

1999 1998 1997

Residential 62.0% 59.9% 60.8%
Small General Service 31.4 32.1 33.1
Large General Service 3.9 3.7 4.2
Sales for Resale and Other 2.7 4.3 1.9
----- ----- -----
Total 100.0% 100.0% 100.0%
===== ===== =====

Retail Gas Sales of MidAmerican Energy By State

1999 1998 1997

Iowa 78.8% 79.0% 79.1%
Illinois 10.3 10.2 10.4
South Dakota 10.1 10.1 9.8
Nebraska 0.8 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 1999, 39% of MidAmerican Energy's electric revenues
were reported in the months of June, July, August and September, and 55% of
MidAmerican Energy's gas revenues were reported in the months of January,
February, March and December.

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 1999, MidAmerican Energy recorded an hourly peak demand of 3,833 MW, which
is 190 MW more than MidAmerican Energy's previous record hourly peak of 3,643 MW
set in 1998.

MidAmerican Energy's accredited net generating capability in the summer of 1999
was 4,466 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 capacity purchases and sales and consists of
Company-owned generation and generation 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 utilities and utilities
in neighboring states and is involved in an electric power pooling agreement
known as Mid-Continent Area Power Pool "MAPP"). MAPP is a voluntary association
of electric utilities doing business in Iowa, Minnesota, Nebraska and North
Dakota and portions of Illinois, 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 1999 was approximately 16.5%.

-13-
<PAGE>

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 authorized 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, 1999, Northern's electricity distribution network (excluding
service connections to consumers) included approximately 17,000 kilometers of
overhead lines and approximately 27,000 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 23,000 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.

Under the terms of its PES license, Northern currently supplies approximately
1.5 million supply customers within its 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 to major users 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.

Total Electric Sales of Northern By Customer Class

1999 1998 1997

Residential 27.5% 32.4% 34.0%
Small General Service 12.7 16.2 16.7
Large General Service 58.1 49.9 47.7
Sales for Resale and Other 1.7 1.5 1.6
----- ----- -----
Total 100.0% 100.0% 100.0%
===== ===== =====

Northern Supply also competes to supply gas inside and outside its authorized
area. At December 31, 1999, Northern supplied gas to approximately 567,000
customers.

Total Gas Sales of Northern By Customer Class

1999 1998 1997

Residential 70.0% 45.5% 14.5%
Commercial 30.0 54.5 85.5
----- ----- -----
Total 100.0% 100.0% 100.0%
===== ===== =====

-14-
<PAGE>

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 approximately 19% 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
- ------------------------------------------------

The Company has ownership interests in generating facilities with an aggregate
of (i) 9,468 net MW in projects in operation representing an aggregate net
capacity owned of 5,195 net MW of electric generating capacity, (ii) 746 net MW
in four projects under construction representing an aggregate net capacity of
672 net MW owned electric generating capacity and (iii) 46 net MW in three
projects in advanced development stages with signed power sales agreements or
under award representing an aggregate net capacity owned of 45 net MW of
electric generating capacity.

-15-
<PAGE>
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.

<TABLE>
<CAPTION>
Facility Net Political
Net MW Commercial U.S. $ Power Risk
Project (1) MW Owned (2) Fuel Location Operation Payments Purchaser (3) Insurance
----------- -------- --------- ----- -------- ----------- -------- ------------- ---------

<S> <C> <C> <C> <C> <C> <C> <C> <C>
Projects in Operation
- ---------------------

Council Bluffs Energy 131 131 Coal Iowa 1954, 1958 Yes MEC No
Center units 1 & 2

Council Bluffs Energy 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
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 1,529 382 Nuclear Illinois 1972 Yes MEC No

Riverside Generation
Station 135 135 Coal Iowa 1925-61 Yes MEC No

Combustion Turbines 789 789 Gas Iowa 1969-95 Yes MEC No

Moline Water Power 3 3 Hydro Illinois 1970 Yes MEC No

Imperial Valley 268 134 Geo California 1986-96 Yes Edison No

Saranac 240 90 Gas New York 1994 Yes NYSEG No

Power Resources 200 100 Gas Texas 1988 Yes TUEC 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 Philippines 1997 Yes PNOC-EDC Yes

Malitbog 216 216 Geo Philippines 1996-97 Yes PNOC-EDC Yes

Upper Mahiao 119 119 Geo Philippines 1996 Yes PNOC-EDC Yes

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 9,468 5,195
===== =====
</TABLE>

- ----------

(1) The Company operates all such projects other than Teesside Power Limited,
Quad Cities Power Station, Ottumwa Generation Station and Desert Peak.

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

(3) PNOC-Energy Development Corporation ("PNOC-EDC"); Government of the
Philippines ("GOP") and Philippine National Irrigation Administration
("NIA") (NIA also purchases water from this facility). The Government of
the Philippines undertaking supports PNOC-EDC's and NIA's respective
obligations. 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"); Northern Electric plc
("Northern"); Zinc Recovery Project ("Zinc") and MidAmerican Energy Company
("MEC").

-16-
<PAGE>
<TABLE>
<CAPTION>

Facility Net Political
Net MW Commercial U.S. $ Power Risk
Project (1) MW Owned (2) Fuel Location Operation Payments Purchaser (3) Insurance
- ----------- -------- --------- ----- -------- ----------- -------- ------------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Projects Under Construction
- ---------------------------

Casecnan 150 105 Hydro Philippines 2001 Yes NIA GOP Yes

Salton Sea V 49 25 Geo California 2000 Yes Zinc/TBD No

CE Turbo 10 5 Geo California 2000 Yes Zinc/TBD No

Cordova 537 537 Gas Illinois 2001 Yes TBD No
------ -----
Total Projects Under
Construction 746 672
------ -----

Development Projects (4)
- ------------------------

Telephone Flat 44 44 Geo California 2001 Yes BPA No

Kirkheaton Wind Ltd. 2 1 Wind England 2000 No Northern No
------ -----
Total Development Projects 46 45
------ -----

Total Power Generation

Projects 10,260 5,912
====== =====
</TABLE>

(1) The Company operates all such projects other than Teesside Power Limited,
Quad Cities Power Station, Ottumwa Generation Station and Desert Peak.

(4) Significant contingencies exist in respect of development projects,
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 that are in more preliminary stages of
development.

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 and
Hanna Basin mines. The use of low-sulfur western coal enables MidAmerican Energy
to comply with the acid rain provisions of the Clean Air Act Amendments ("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. 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.

-17-

<PAGE>

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. Coal is delivered directly to MidAmerican Energy's Neal Energy
Center by the UP and to Council Bluffs Energy Center ("CBEC") by the UP and the
BNSF. 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 interchange points 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.

MidAmerican Energy is a 25% joint owner of Quad Cities Nuclear Power Station.
MidAmerican Energy has been advised by Commonwealth Edison ("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 through
2001 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 2003. Commitments for fuel fabrication have been obtained at
least through 2005. 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 LLC ("CE Generation"), a 50% owned subsidiary of the Company,
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") consist of the Vulcan, Hoch (Del
Ranch), Elmore and Leathers projects (the "Vulcan Project," the "Hoch (Del
Ranch) Project," the "Elmore Project" and the "Leathers Project," respectively).
The remaining four operating Imperial Valley Project plants (the "Salton Sea
Projects") consist of Salton Sea I, II, III and IV projects. (the "Salton Sea I
Project" the "Salton Sea II Project, the "Salton Sea III Project and the "Salton
Sea IV Project", respectively).

Vulcan. The Vulcan Project sells electricity to Southern California Edison
Company ("Edison") under a 30-year Standard Offer No. 4 Agreement ("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. Thereafter, the energy payments are based on
Edison's Avoided Cost of Energy.

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

-18-
<PAGE>

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 expired 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 that is currently $132.58 per kW-year. The contract
capacity payment adjusts quarterly based on a basket of energy indices for the
term of the Salton Sea I PPA. The energy payment is calculated using a Base
Price (defined as the initial value of the energy payment (4.701 cents per kWh
for the second quarter of 1992)), which is subject to quarterly adjustments
based on a basket of indices. The time period weighted average energy payment
for Salton Sea I was 5.3 cents per kWh during 1999. As the Salton Sea I PPA is
not an SO4 Agreement, the energy payments do not revert to Edison's Avoided Cost
of Energy.

Salton Sea II Project. The Salton Sea II Project sells electricity to Edison
pursuant to a 30-year modified SO4 Agreement that commenced on April 5, 1990.
The contract capacity and contract nameplate are 15 MW (16.5 MW during on-peak
periods) and 20 MW, respectively. The contract requires Edison to make capacity
payments, capacity bonus payments and energy payments. The price for contract
capacity and contract capacity bonus payments is fixed for the life of the
modified SO4 Agreement. The energy payments for the first ten-year period, which
period expires on April 4, 2000, are levelized at a time period weighted average
of 10.6 cents per kWh. Thereafter, the monthly energy payments will be Edison's
Avoided Cost of Energy. 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 I PPA option
(20 MW) and to the original Salton Sea IV SO4 Agreement ("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

CE Generation affiliates currently operate the Saranac, Power Resources and Yuma
natural gas plants (the "Saranac Project", "Power Resources Project" and "Yuma
Project", respectively) and previously operated the NorCon natural gas plant
(the "NorCon Project"). (The Saranac Project, Power Resources Project, Yuma
Project and NorCon Project are collectively referred to as the "Gas Plants").

-19-
<PAGE>

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
("Yuma PPA"). 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 Yuma PPA. 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, Yuma Cogeneration Associates ("YCA"),
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 qualifying facility ("QF") and as PURPA. However,
if the industrial entity terminates the agreement, YCA 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 YCA and
Southwest Gas Corporation.

Saranac Project. The Saranac Project is a 240 net MW natural gas-fired
cogeneration facility located in Plattsburgh, New York, which began commercial
operation in June 1994. The Saranac Project has entered into a 15-year power
purchase agreement (the "Saranac PPA") with New York State Electric & Gas
("NYSEG"). The Saranac Project 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. The Saranac Project has a
15-year natural gas supply contract (the "Saranac Gas Supply Agreement") with
Shell Canada Limited ("Shell Canada") to supply 100% of the Saranac Project'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 the Saranac Project. 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 ("GECC").

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 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.
-20-
<PAGE>

The Saranac Partnership 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. The Saranac Partnership believes that NYSEG's claims are without merit for
the same reasons described in the FERC's orders.

Power Resources Project. The Power Resources Project is a 200 net MW natural
gas-fired cogeneration project located near Big Spring, Texas, which has a
15-year power purchase agreement (the "Power Resources PPA") with Texas
Utilities Electric Company. The Power Resources Project began commercial
operation in June 1988. The Power Resources Project is a QF and the project
entity, Power Resources Ltd. ("Power Resources"), 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 "CE Texas Gas Supply
Agreement") with CE Texas Gas L.P. ("CE Texas Gas") for Power Resources' fuel
requirements through December 2003. In June 1995, CE Texas Gas and Louis Dreyfus
Natural Gas Corp. ("Dreyfus") executed an eight-year natural gas supply
agreement (the "CE Texas Gas-Dreyfus Gas Supply Agreement"), with which CE Texas
Gas will fulfill its supply commitment to Power Resources 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 CE Texas Gas Gas Supply
Agreement contains rates that are fixed for the respective contract terms.
Revenues escalate at a higher rate than fuel costs.

NorCon Project. The NorCon Project is an 80 net MW natural gas-fired
cogeneration facility located in North East, Pennsylvania which began commercial
operation in December 1992. The NorCon Project had a 25-year power purchase
agreement (the "NorCon PPA") with Niagara Mohawk Power Corporation ("NIMO"). On
December 2, 1999, the NorCon Project was transferred to GECC and the NorCon PPA
was terminated. The Company no longer retains an interest in the NorCon Project.

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.

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. Northern owns 50% of this 50MW gas fired mid merit power plant located
on Teesside. The plant is currently in the commissioning stage, however due to
combustor issues it is unlikely to pass the performance criteria required for
handover until 2001. NEGL is being held financially whole by the turnkey
contractor (Rolls Royce) until the plant is fit for purpose at which time the
plant will be operated by NEGL. The plant will be used as part of

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Northern's strategy to hedge the purchases and sales of electricity and gas,
together with obtaining the benefits of avoided charges together with sales
premiums.

The Philippines Power Generation

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

Upon completion of the transmission line, the construction loan was converted to
a term loan in May 1998. Export-Import Bank of the United States ("Ex-Im Bank")
and United Coconut Planters Bank of the Philippines are providing the term
loans.

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-Energy Development Corporaiton
("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 (e.g., war, nationalization,
etc.). In addition, PNOC-EDC must continue to make Capacity Fee payments if
there is a force majeure event 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 PNOC-EDC, which in turn sells
the power to NPC for distribution to the island of Luzon. During

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<PAGE>

the period of constrained operation, PNOC-EDC was required to, and paid all
capacity fees under the take or pay provisions of the contract.

Upon completion of the transmission line, the construction loan was converted to
a term loan in June 1998. The project financing term loan is being provided by
OPIC and Ex-Im Bank.

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.

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

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 thenet 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.

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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.

CalEnergy Minerals LLC ("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"). Four facilities will be
installed near Imperial Valley Project sites to extract a zinc chloride solution
from the 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.
In September 1999, Minerals LLC entered into a sales agreement whereby all zinc
produced by the Zinc Recovery Project will be sold to Cominco, Ltd. The initial
term of the agreement expires in December 2005.

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. The payment obligations of Kvaerner,
including payment of liquidated damages of up to 20% of the contract price for
certain delays or failures to meet performance guarantees, are secured by a
letter of credit issued by Union Europeenne de CIC (or another financial
institution rated "A" or better by S&P or "A2" or better by Moody's and
otherwise acceptable to Minerals LLC) in an initial aggregate amount equal to
$29.6 million. The Zinc Recovery Project is scheduled to commence initial
operations in mid-2000.

Salton Sea V. Salton Sea Power LLC, an indirect wholly owned subsidiary of CE
Generation, is constructing the Salton Sea V Project. The Salton Sea V Project
is 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") or other market transactions. The Salton
Sea V Project 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"). The Salton
Sea V Project is schedule to commence commercial operation in mid-2000.

CE Turbo. CE 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 or other market transactions. 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 Imperial Valley Project. The CE Turbo Project and the
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 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 mid-2000.

Cordova. Cordova Energy Company LLC ("Cordova Energy"), a wholly owned
subsidiary of the Company, financed and commenced construction of a 537 MW gas
fired combined cycle merchant power plant to be located northeast of the Quad
Cities in Cordova, Illinois. The Cordova Project is being constructed by SWEC
pursuant to a date certain, fixed price, turnkey engineering, procurement and
construction contract. Cordova is scheduled to commence commercial operation in
mid-2001.

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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 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.

On November 20, 1999, the Casecnan Construction Contract was amended to extend
the Guaranteed Substantial Completion Date for the Casecnan Project to March 31,
2001. Accordingly, the Casecnan Project is now expected to become operational by
the second quarter of 2001.

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<PAGE>

Under the Project Agreement, if NIA has completed certain work on its irrigation
system, CE Casecnan is liable to pay NIA $5,000 per day for each day of delay in
completion of the Casecnan Project beyond July 27, 2000, increasing to $13,500
per day for each day of delay in completion beyond November 27, 2000.

CE Casecnan's ability to make payments on any of its existing and future
obligations is dependent on NIA's and the Republic of the Philippines'
performance of their obligations under the Project Agreement and the Performance
Undertaking, respectively. No shareholders, partners or affiliates of CE
Casecnan, including the Company, and no directors, officers or employees of the
Company will guarantee or be in any way liable for payment of CE Casecnan's
obligations. As a result, payment of CE Casecnan's obligations depends upon the
availability of sufficient revenues from CE Casecnan's business after the
payment of operating expenses.

NIA's payments of obligations under the Project Agreement are substantially
denominated in United States dollars and are expected to be CE Casecnan's sole
source of operating revenues. Because of CE Casecnan's dependence on NIA, any
material failure of NIA to fulfill its obligations under the Project Agreement
and any material failure of the Republic of the Philippines to fulfill its
obligations under the Performance Undertaking would significantly impair the
ability of CE Casecnan to meet its existing and future obligations.

United Kingdom

Northern Generation owns 75% of a 1.8 MW wind farm currently under construction
near Kirkheaton, Northumberland. The project is being built by Nordex Gmbh of
Germany, and has a total cost of approximately 1.5 million pounds sterling. The
project is scheduled for commercial operation in the second quarter of 2000.

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.

United Kingdom

The Company, through Northern Generation, is pursuing a number of project
opportunities including several small embedded combined heat and power and
peaking facilities, (totaling up to 80 MW) to provide electricity to suppliers
on a local basis across Southern England. In addition, a larger 100 MW combined
heat and power project is under development in Southern England with an
industrial host. This project is processing through the later stages of
government review and approval.

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<PAGE>

The gas moratorium in the U.K. has significantly adversely impacted the ability
to develop gas-fired plants in the U.K.

Producing Gas Field Operations and Fields in Development
- --------------------------------------------------------

CalEnergy Gas (UK) Limited. CalEnergy 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, the EP389 (Gingin) concession in the Perth Basin in Australia and the
Yolla discovery in the Bass Basin of Australia.

PRODUCING GAS FIELDS SHARE OF CURRENT LOCATION
REMAINING % WORKING
RESERVES INTEREST
BCF(1)

Windermere 8.7 20.000% U.K. Offshore (North Sea)
Victor 8.6 5.000% U.K. Offshore (North Sea)
Schooner 7.4 2.070% U.K. Offshore (North Sea)
Johnston 32.9 22.113% U.K. Offshore (North Sea)
Anglia 82.7 67.198% U.K. Offshore (North Sea)

FIELDS IN DEVELOPMENT Size Km2
Pila Area Concession 13,000(2) 100.000% N.W. Poland (Polish Trough)
EP389 (Gingin) 2,960 40.789% S.W. Australia Onshore (Perth Basin)
Yolla Discovery 550 20.000 S.E. Australia Offshore (Bass Basin)

- ---------------------------

(1) Gas reserves in Billion cubic feet (or "Bcf") as of December 31, 1999. 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) Subject to 25% relinquishment of the original area after every 2 years
during the 8 year contract term based on work program results.

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 8.7 bcf net to CE Gas. The field is produced by an
unmanned platform that 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 that commenced production in April
1997 and currently has average net production of 6.52 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 remaining reserves of 8.6 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

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<PAGE>

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 production of 4.7 MM
scfd and sells its gas to British Gas Trading Limited. CE Gas holds a 5% working
interest in this field.

Schooner Field. The Schooner Field is located in the Northern part of the
Southern North Sea and has remaining net reserves of 7.4 bcf. The field is
produced by an unmanned platform which is tied back through an 18 mile 16"
flowline to the Murdoch platform. Production is achieved from seven wells. The
gas is transported through the CMS pipeline to the Theddlethorpe shore terminal.
CE Gas holds a 2.07% working interest in the Schooner Field, which commenced
production in October 1996 and currently has average net production of 2.47
MMscfd. The CE Gas share of the gas is sold to Northern.

Johnston Field. The Johnston gas field is located in the Northern part of the
Southern North Sea approximately 56 miles north east of Scarborough on the U.K.
coast and has remaining reserves of 32.9 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. The current average net production rate is 11.7 MMscfd. Gas
is sold to TXU Europe Upstream Limited. CE Gas has a 22.113% working interest in
this field following the outcome of an equity redefinition process during 1999.
CE Gas previously had an 18.264% working interest in the field.

Anglia Field. During 1999, CE Gas acquired a 67.198% interest in the Anglia
Field from Ranger Oil (U.K.) Ltd. and Ranger Oil (PC) Ltd. Following the
acquisition, CE Gas took over the role of operator of the field. The Anglia
Field is located in the central part of the Southern North Sea, approximately 65
miles east of the Theddlethorpe terminal on the U.K. coast, and has remaining
reserves of 82.7 Bcf net to CE Gas. Anglia is produced via an unmanned platform
which has six production wells, and a further two subsea production wells are
tied back to the platform via an 8" pipeline. The gas is exported via a 12"
pipeline to the LOGGS platform and then onwards to the Theddlethorpe shore
terminal. The Anglia Field has been on production since October 1992 and
currently has an average production of 31.5 MM/scfd net to CE Gas. CE Gas sells
the gas to National Power and Northern.

Projects in Development

Pila Concession. Following the execution of a Mining Usufruct Agreement in 1997
with the Polish government, CE Gas was awarded an eight year exploration and
exploitation agreement in April 1998 providing it with the exclusive right (a
100% working interest) to explore and 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 program (now completed) 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. Only developed areas
can 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.

EP389 (Gingin) Concession. In August 1997, CE Gas signed an earn-in agreement
with Empire Oil of Australia, the permit holder for various concession areas in
the Perth Basin in Western Australia. Under the agreement, CE Gas has now earned
a 40.789% working interest in the main concession area and a 33% working
interest in four ancillary concession areas. Given the advantages of the
location of the Gingin concession, in close proximity to an industrial area and
electric residential load center, the Company believes that the Gingin
concession 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 Western Australia. 95% of all gas to SW Australia is currently supplied from
the NW shelf (Dampier to Bunbury pipeline--1500km). The 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.

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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, CE Gas 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. A successful
appraisal well was drilled in 1999. CE Gas' net remaining reserves are estimated
at approximately 70 Bcf. The Yolla partners are currently reviewing the
development options for the field.

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.

Other
- -----

HomeServices

The Company owns approximately 65% of HomeServices.Com Inc. ("HomeServices"),
the second largest residential real estate brokerage firm in the United States
based on aggregate closed transaction sides in 1998 for its various brokerage
firm operating subsidiaries. Closed transaction sides mean either the buy side
or sell side of any closed home purchase and is the standard term used by
industry participants and publications to rank real estate brokerage firms. In
addition to providing traditional residential real estate brokerage services,
HomeServices cross sells to its existing real estate customers preclosing
services, such as mortgage origination and title services, including title
insurance, title search, escrow and other closing administrative services,
assists in securing other preclosing and postclosing services provided by third
parties, such as home warranty, home inspection, home security, property and
casualty insurance, home maintenance, repair and remodeling and is developing
various related e-commerce services. HomeServices currently operates primarily
under the Edina Realty, Iowa Realty, J.C. Nichols Residential, CBSHOME, Paul
Semonin Realtors, Long Realty and Champion Realty brand names in the following
twelve states: Minnesota, Iowa, Arizona, Kansas, Missouri, Kentucky, Nebraska,
Wisconsin, Indiana, Maryland, North Dakota and South Dakota. HomeServices
occupies the number one or number two market share position in each of its major
markets based on aggregate closed transaction sides for the year ended December
31, 1998. HomeServices' major markets consist of the following metropolitan
areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa; Omaha, Nebraska;
Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri; Tucson,
Arizona and Annapolis, Maryland.

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 Republic of Indonesia
("ROI") provided sovereign guarantees of the obligations under the "take-or-pay"
contracts.

HCE's 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 defaulted on the contractually required and sovereign guaranteed
"take-or-pay" payment obligations. The Indonesian Subsidiaries in 1998 initiated
dispute resolution procedures under the ESCs and the sovereign guarantees with
PLN and the Republic of Indonesia and subsequently commenced arbitration to
resolve the dispute. The arbitration before an international arbitration panel
was concluded in 1999 and found that the ROI had materially breached the
contract obligations and sovereign guarantees and violated international law.
The final arbitration awards directed the ROI to pay HCE $393.4 million and PPL
$182.2 million.

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When the ROI failed to pay the arbitration awards, the Company filed claims with
OPIC, an agency of the U.S. Government, and Lloyds private market insurers
pursuant to certain insurance that covered political risks relating to the
projects. In 1999, the Company received payment of the claims filed with OPIC
and Lloyds totaling $290 million and assigned the Indonesia Subsidiaries
(including the arbitration award) to OPIC.

Regulatory, Energy and Environmental Matters
- --------------------------------------------

United States

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

Each of the 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.

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<PAGE>

CAAA was signed into law in November 1990. 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. 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. 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 of 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.

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<PAGE>

connection with the licensing regime for electricity and gas utilities,
electricity and gas regulatory institutions and procedures, and social, consumer
and environmental protection related to utilities.

Employees
- ---------

At December 31, 1999, the Company and its subsidiaries employed approximately
9,700 people. Neither the Gas Projects nor the Imperial Valley Project entities
hire or retain any employees. All employees necessary to operate the Gas
Projects and Imperial Valley Projects are provided by affiliates of the Company
under certain administrative services and operation and maintenance agreements.
International development activities in 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 Philippine
affiliates currently maintain offices in Manila.

Of Northern's employees, at December 31, 1999, 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.

Of MidAmerican Energy's employees, approximately one half are represented by
labor unions. MidAmerican Energy believes that its relations with its employees
are good.

As of December 31, 1999, HomeServices employed approximately 1,575 individuals
and had approximately 6,350 sales associates, who are independent contractors
and not employees. None of HomeServices' employees or sales associates is
covered by a collective bargaining agreement. Management believes that
HomeServices' relations with its employees and sales associates 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
buildings. At December 31, 1999, Northern had freehold and leasehold interests
in approximately 8,500 network properties, comprising principally sub-station
sites. The recorded historical cost account net book value of total network land
and buildings at December 31, 1999 was pounds sterling 25.9 million. Northern
owns, directly or indirectly, the freehold or leasehold interests of such land
and buildings. At December 31, 1999, Northern had freehold and leasehold
interests in approximately 78 non-network properties comprising chiefly offices,
retail outlets, depots, warehouses and workshops. The recorded historical cost
account net book value of total non-network land and buildings at December 31,
1999 was 17.5 million pounds sterling.

MidAmerican Energy's utility properties consist of physical assets necessary and
appropriate to render electric and gas service in its service territories.
Electric property consists primarily of generation, transmission and
distribution facilities. Gas property consists primarily of 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, 1999,
included 897 miles of 345-kV lines, 1,299 miles of 161-kV lines, 1,806 miles of
69-kV lines and 219 miles of 34.5-kV lines. The gas distribution facilities of
MidAmerican Energy at December 31, 1999, included 19,907 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.

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<PAGE>

The Company also maintains an inventory of approximately 150,000 acres of
geothermal property leases. Certain of the producing acreage owned by Magma is
leased to unaffiliated power 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. The
Company leases its principal executive offices and its offices in Manila.

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.

HomeServices' principal offices are located in Edina, Minnesota, where
HomeServices leases approximately 46,000 square feet of office space. This lease
expires in 2003. The rent under this lease is approximately $600,000 per year.
In addition, HomeServices has a total of 160 branch offices, substantially all
of which are leased. HomeServices' office leases generally have initial terms
ranging from three to ten years, with an option to extend the lease for
additional periods. The leases are typically net leases, which means that
HomeServices is required to pay property taxes, utilities and maintenance.
HomeServices believes that its present facilities are adequate for its current
level of operations.

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 and utility subsidiaries
are parties to litigation or other disputes.

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

Not applicable.

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PART II

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

As of March 14, 2000, the Company's equity securities are owned by the members
of the Investor Group and are not registered with the Securities and Exchange
Commission pursuant to the Securities Act of 1933, as amended, listed on a stock
exchange or otherwise publicly held or traded.

ITEM 6. SELECTED FINANCIAL DATA

Reference is made to Part IV of this report.

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

Reference is made to Part IV of this report.

ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

Reference is made to Part IV of this report.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Reference is made to Part IV of this report.

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

Not applicable.
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<PAGE>

PART III

MANAGEMENT

ITEM 10. DIRECTORS, EXECUTIVE AND OTHER OFFICERS OF THE COMPANY AND SIGNIFICAN
SUBSIDIARIES

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
Patrick J. Goodman Senior Vice President and Chief
Financial Officer MEHC, MEC
Steven A. McArthur Senior Vice President, Mergers and
Acquisitions and Secretary MEHC, MEC
John A. Rasmussen Jr. Senior Vice President and
General Counsel MEHC, MEC
Keith D. Hartje Senior Vice President and Chief
Administrative Officer MEHC, MEC
Robert S. Silberman Senior Vice President and President,
CalEnergy Generation MEHC
Douglas L. Anderson Vice President, Assistant General
Counsel and General Counsel,
CalEnergy Generation MEHC
Edward F. Bazemore Vice President, Human
Resources/IPP MEHC, MEC
James A. Flores Vice President, Project
Finance MEHC
Adrian M. Foley III Vice President, Marketing MEHC
Brian K. Hankel Vice President and Treasurer MEHC, MEC
Paul J. Leighton Vice President Corporate Law,
Assistant General Counsel
and Assistant Secretary MEHC, MEC
Joseph M. Lillo Vice President and Controller MEHC
James J. Sellner Director of Taxation, Corporate MEHC, MEC
K. Taylor Smith Controller, Asian Operations MEHC
Jonathan M. Weisgall Vice President, Federal
Regulation MEHC, MEC
Russell H. White Assistant Vice President,
General Services MEHC, MEC
Cathy S. Woollums Vice President, Environmental MEHC, MEC
Ronald W. Stepien President MEC
Jack L. Alexander Senior Vice President, Transmission
and Energy Delivery MEC
David C. Caris Vice President, State
Government Affairs MEC
Dean A. Crist Vice President, Generation MEC
Steven J. Dust Vice President, Economic
Development MEC
Brent E. Gale Vice President, Legislation
and Regulation MEC
David L. Graham Vice President, Customer Service MEC
James J. Howard Vice President, Regulatory
Affairs MEC
Todd M. Raba Vice President, Retail Business
Unit MEC
Mark W. Roberts Vice President, Energy Trading
and Planning MEC
Thomas B. Specketer Vice President & Controller MEC
Steven R. Weiss Assistant General Counsel MEC
P. Eric Connor President and Chief Operating
Officer Northern
Dave Crompton Managing Director, Retail Northern
Dr. John M. France Director of Regulation Northern
G. Valerie Giles Company Secretary Northern
Mark Horsley Managing Director, Northern
Utility Services Limited Northern
Dr. Philip S. Lawless Managing Director, Generation Northern
Ken Linge Director of Finance Northern

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<PAGE>

Neil Middleton Managing Director, Northern
Electric Supply Limited Northern
James D. Stallmeyer Vice President, Commercial
Director and General Counsel Northern
David Swan Distribution Director Northern
David A. Waters Managing Director, Northern
Electric Distribution Limited Northern
Peter Youngs Managing Director, CalEnergy
Gas (UK) Ltd. Northern

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

DAVID L. SOKOL, 43, 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, 37, President and Chief Operating Officer. Mr. Abel joined the
Company in 1992 and initially served as Vice President and Controller. Mr. Abel
is a Chartered Accountant and from 1984 to 1992 he was employed by Price
Waterhouse. As a Manager in the San Francisco office of Price Waterhouse, he was
responsible for clients in the energy industry.

PATRICK J. GOODMAN, 33, Senior Vice President and Chief Financial Officer. Mr.
Goodman joined the Company in 1995, and served in various accounting positions
including Senior Vice President and Chief Accounting Officer. Prior to joining
the Company, Mr. Goodman was a financial manager for National Indemnity Company
and a senior associate at Coopers & Lybrand.

STEVEN A. McARTHUR, 42, Senior Vice President, Mergers and Acquisitions and
Secretary. Mr. McArthur joined the Company in February 1991 and has served in
various executive capacities including General Counsel. 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., 54, 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.

KEITH D. HARTJE, 50, Senior Vice President and Chief Administrative Officer. Mr.
Hartje has been with MidAmerican Energy and its predecessor companies since
1973. In that time, he has held a number of positions, including General Counsel
and Corporate Secretary, District Vice President for southwest Iowa operations,
and Vice President, Corporate Communications.

ROBERT S. SILBERMAN, 42, Senior Vice President. 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.

DOUGLAS L. ANDERSON, 42, 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. Prior to that, Mr. Anderson was a principal in the firm
Anderson & Anderson.

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<PAGE>

EDWARD F. BAZEMORE, 63, 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.

JAMES A. FLORES, 46, Vice President, Project Finance. Mr. Flores joined the
Company 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, 53, 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 the Company, 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.

BRIAN K. HANKEL, 37, 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.

PAUL J. LEIGHTON, 46, 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, 30, Vice President and Controller. Mr. Lillo joined the Company
in November 1996, and served as Manager of Financial Reporting and was promoted
to Controller/IPP in March 1998. Mr. Lillo was promoted to Controller in July
1999. Prior to joining the Company, Mr. Lillo was a senior associate with
Coopers & Lybrand LLP.

JAMES J. SELLNER, 53, Director of Taxation. Mr. Sellner joined the Company in
November, 1997. Prior to joining the Company, Mr. Sellner was employed by
Central and South West Corporation and Banc One/MCorp.

K. TAYLOR SMITH, 43, 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, 51, 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, 53, 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, 39, 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.

RONALD W. STEPIEN, 53, President of MidAmerican Energy since November 1, 1998,
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, a predecessor company, from 1990 to 1995.

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<PAGE>

JACK L. ALEXANDER, 52, Senior Vice President of MidAmerican Energy. 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, 40, Vice President, State Government Affairs of MidAmerican Energy.
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.

DEAN A. CRIST, 44, Vice President, Generation of MidAmerican Energy. Mr. Crist
has been in his present position since April 9, 1999 and was Generation
Marketing Vice President of MidAmerican Energy from April 1, 1998 to April 9,
1999 and held various management positions with MidAmerican Energy and its
predecessor companies for more than five years prior thereto.

STEVEN J. DUST, 45, Vice President, Economic Development of MidAmerican Energy.
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, 48, Vice President, Legislation and Regulation of MidAmerican
Energy. 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 company.

DAVID L. GRAHAM, 54, Vice President, Customer Service, of MidAmerican Energy.
Mr. Graham has been in his present position since December 1998 and was Sales
Vice President from April 1998 to December 1998, and held various management
positions with MidAmerican Energy and its predecessor companies for more than 30
years prior thereto.

JAMES J. HOWARD, 57, Vice President, Regulatory Affairs of MidAmerican Energy.
Mr. Howard has been Vice President, Regulatory Affairs since April, 1998.
Previously he had been Vice President, Administrative Services since 1989.

TODD M. RABA, 43, Vice President, Marketing and Sales. Mr. Raba has been in his
present position since April 1999. He joined MidAmerican in December 1997 as
Sales Vice President, responsible for Major Accounts. Prior to joining
MidAmerican, Mr. Raba spent 13 years at Rollins Environmental Services, Inc., of
Wilmington Delaware. His most recent assignments there included Northeast Region
Vice President and National Director of Sales.

MARK W. ROBERTS, 43, Vice President, Energy Trading and Planning of MidAmerican
Energy. Mr. Roberts has been in his present position since April 1999 and was a
manager and then vice president of MidAmerican Energy's generation business
services from December 1996 to April 1999. Prior to that time, Mr. Roberts held
various management positions with MidAmerican Energy and its predecessor
companies for more than five years.

THOMAS B. SPECKETER, 43, Vice President and Controller of MidAmerican Energy
Company. Mr. Specketer has been in his present position since September 1999 and
has over twenty years of accounting and tax experience with MidAmerican Energy
and its predecessor companies.

STEVEN R. WEISS, 45, Assistant General Counsel of MidAmerican Energy. 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

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<PAGE>

MidAmerican Energy he served as a Hearing Examiner for the Illinois Commerce
Commission from 1982 until 1987.

P. ERIC CONNOR, 51, Director, Northern Electric and President and Chief
Operating Officer, Northern Electric. Mr. Connor joined Northern in 1992 as a
Director. Prior to joining Northern, he was a Director at NEI 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 &
Defense.

DAVE CROMPTON, 46, 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.

DR. JOHN M. FRANCE, 42, Director, Northern Electric and Director of Regulation,
Northern Electric. Mr. France joined Northern in 1989 as Regulation Manager.
Between 1982 to 1989, Mr. France held a number of regulatory positions with
British Gas.

G. VALERIE GILES, 48, 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.

NEIL MIDDLETON, 35, Managing Director, Northern Electric Supply Limited. Mr.
Middleton joined Nothern in 1989 having studied Electrical and Electronics
Engineering at the University of Newcastle Upon Tyne. Prior to taking up his
current appointment, Mr. Middleton worked in the Pricing and Purchasing
Departments.

DR. PHILIP S. LAWLESS, 38, 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, 50, Director of Finance, Northern Electric. Mr. Linge joined Northern
as an accountancy trainee in 1968. He has held a variety of finance posts.
Current responsibilities include financial planning, taxation, treasury,
pensions, and group accounting services.

MARK HORSLEY, 40, Managing Director, Northern Utility Services Limited. Mr.
Horsley joined Northern in 1975 as a craft apprentice and subsequently held a
number of progressing senior engineering positions.

JAMES D. STALLMEYER, 42, Director, Northern Electric and Vice President and
Commercial Director and General Counsel, Northern Electric. Mr. Stallmeyer
joined the Company in 1993. Mr. Stallmeyer practiced in the public finance and
banking areas at Chapman and Cutler in Chicago from 1984 to 1987 and in the
corporate finance department from 1989 to 1993. Prior to that, Mr. Stallmeyer
was an attorney in the public finance department of the Chicago office of
Skadden, Arps, Slate, Meagher & Flom in 1987 and 1988 and was a legal writing
instructor at the University of Illinois College of Law in 1988 and 1989.

DAVID SWAN, 55, Distribution Director. 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.

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<PAGE>

DAVID A. WATERS, 57, Managing Director, Northern Electric Distribution Limited.
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, 45, 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.

ITEM 11. EXECUTIVE COMPENSATION

To be filed by amendment.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

To be filed by amendment.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

To be filed by amendment.

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<PAGE>

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) Financial Statements and Schedules

1. Financial Statements (included herein)
Page No.
Selected Consolidated Financial Data...............................42
Management's Discussion and Analysis of Financial Condition
And Results of Operations........................................43
Qualitative and Quantitative Disclosures About Market Risk.........56
Consolidated Balance Sheets as of December 31, 1999 and 1998.......59
Consolidated Statements of Operations
For the Three Years Ended December 31, 1999, 1998 and 1997.......60
Consolidated Statements of Stockholders' Equity
For the Three Years Ended December 31, 1999, 1998 and 1997.......61
Consolidated Statements of Cash Flows
For the Three Years Ended December 31, 1999, 1998 and 1997.......62
Notes to Consolidated Financial Statements.........................63
Report of Independent Accountants..................................96

2. Financial Statement Schedules Page No.

Schedule I, Financial Statements of the Company
(Parent Company only)............................................97

(b) Reports on Form 8-K

The Company filed a Current Report on Form 8-K dated October 8, 1999
announcing received tenders and consent from holders of an aggregate
of $119 million principal amount of its 9 1/2% Senior Notes due 2006.

The Company filed a Current Report on Form 8-K dated October 20, 1999
announcing that the International Arbitration Panel announces
favorable final decisions for Himpurna California Energy and Patuha
Power requiring Republic of Indonesia to pay $575,000,000.

The Company filed a Current Report on Form 8-K dated October 21, 1999
announcing that on October 20, 1999, it has established the final
pricing for the tender of its 9 1/2% Senior Notes due 2006, in
connection with its previously announced cash tender offer and consent
solicitation for such Notes.

The Company filed a Current Report on Form 8-K dated October 24, 1999
announcing that it had entered into an Agreement and Plan of Merger,
dated as of October 24, 1999 with entities formed by an investor group
including Berkshire Hathaway Inc., Walter Scott, Jr. and David L.
Sokol.

The exhibits listed on the accompanying Exhibit Index are filed as
part of this Annual Report.

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

Not applicable.

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<PAGE>

SELECTED CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>

YEAR ENDED DECEMBER 31
-------------------------------------------------------------------------
1999 (1) 1998(2) 1997 1996(3) 1995(4)
----------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating revenue $ 4,128,737 $2,555,206 $2,166,338 $ 518,934 $ 335,630
Total revenue 4,398,783 2,682,711 2,270,911 576,195 398,723
Total costs and expenses 4,041,714 2,410,658 2,074,051 435,791 301,672
Income before provision for
income taxes 357,069 272,053 196,860(6) 140,404 97,051
Minority interest 46,923 41,276 45,993 6,122 3,005
Income before change in accounting
principle and extraordinary item 216,671(5) 137,512 51,823(6) 92,461 63,415
Extraordinary item, net of tax (49,441) (7,146) (135,850) -- --
Cumulative effect of change in
accounting principle, net of tax -- (3,363) -- -- --
Net income (loss) 167,230(5) 127,003 (84,027)(6) 92,461 63,415
Income per share before change in
accounting principle and
extraordinary item $ 3.62(5) $ 2.29 $ 0.77(6) $ 1.69 $ 1.32
Extraordinary item per share (.83) (.12) (2.02) -- --
Cumulative effect of change in
accounting principle per share -- (.06) -- -- --
Net income (loss) per share $ 2.79(5) $ 2.11 $ (1.25)(6) $ 1.69 $ 1.32
Basic common shares outstanding 59,929 60,139 67,268 54,739 47,249
Income per share before extraordinary
item and cumulative effect of change
in accounting - diluted $ 3.28(5) $ 2.15 $ 0.75(6) $ 1.54 $ 1.22
Extraordinary item - diluted (.69) (.10) (1.97) -- --
Cumulative effect of change in
accounting principle - diluted -- (.04) -- -- --
Net income (loss) per share - diluted $ 2.59(5) $ 2.01 $ (1.22)(6) $ 1.54 $ 1.22
Diluted shares outstanding 71,948 74,100 68,686 65,072 56,195

BALANCE SHEET DATA:
Total assets $10,766,352 $9,103,524 $7,487,626 $5,630,156 $2,654,038
Total liabilities 8,978,924 7,598,040 5,282,162 4,181,052 2,084,474
Company-obligated mandatorily
redeemable convertible preferred
securities of subsidiary trusts 450,000 553,930 553,930 103,930 --
Subsidiary-obligated mandatorily
redeemable preferred securities
of subsidiary trusts 101,598 -- -- -- --
Preferred securities of subsidiaries 146,606 66,033 56,181 136,065 --
Total stockholders' equity 994,588 827,053 765,326 880,790 543,532

</TABLE>

(1) Reflects the MidAmerican Merger owned for a portion of the year,
the disposition of Coso Joint ventures during the year, and the
disposition of 50% ownership interest in CE Generation
(2) Reflects the acquisition of KDG.
(3) Reflects the acquisitions of Northern, Falcon Seaboard and the
Partnership Interest owned for a portion of the year.
(4) Reflects the acquisition of Magma Power Company owned for a portion of
the year.
(5) Includes $81,556, $1.36 per basic share and $1.13 per diluted share
for non-recurring Indonesia gain on settlement, gains on sales of
McLeod and qualified facilities, Northern restructuring charges and
Berkshire transaction costs.
(6) Includes the $87,000, $1.29 per basic share, $1.27 per diluted share,
non-recurring Indonesian asset impairment charge.

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<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

Business of MEHC

MidAmerican Energy Holdings Company (the "Company" or "MEHC"), is a United
States-based privately owned global energy company with publicly traded fixed
income securities that generates, distributes and supplies energy to utilities,
government entities, retail customers and other customers located throughout the
world. Through its subsidiaries the Company is organized and managed on three
separate platforms:

MidAmerican

MidAmerican Energy ("MEC") is the largest energy company headquartered in Iowa
and is a regulated public utility principally engaged in the business of
generating, transmitting, distributing and selling electric energy and in
distributing, selling and transporting natural gas. MEC distributes electricity
at retail in Iowa, Illinois and South Dakota. It also distributes natural gas at
retail in Iowa, Illinois, South Dakota and Nebraska. As of December 31, 1999,
MEC had 663,500 retail electric customers and 638,000 retail natural gas
customers.

In addition to retail sales, MEC delivers electric energy to other utilities,
marketers and municipalities who distribute it to end-use customers. These sales
are referred to as sales for resale or off-system sales. It also transports
natural gas through its distribution system for a number of end-use customers
who have independently secured their supply of natural gas.

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

MEC has a residential, agricultural, commercial and diversified industrial
customer group, in which no single industry or customer accounted for more than
5% of its total 1999 electric operating revenues or 3% of its total 1999 gas
operating margin. Among the primary industries served by MEC are those that 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.

Most of MEC's business is conducted in a rate-regulated environment and
accordingly, many of its decisions as to the source and use of resources and
other strategic matters are evaluated from a utility business perspective. MEC's
operations are seasonal in nature with a disproportionate percentage of revenues
and earnings historically being earned in the Company's first and third
quarters.

MidAmerican Capital Company manages marketable securities and passive investment
activities, security services and other energy-related, nonregulated activities.
MidAmerican Services Company provides energy management and related services.
Midwest Capital Group, Inc. functions as a regional business development company
in MEC's service territory.

Through October 6, 1999, MHC Inc. owned approximately 95% of the common stock of
MidAmerican Realty Services. On October 6, 1999, MidAmerican Realty Services was
dividended out of MHC Inc. to the Company and merged with HomeServices.Com
("HomeServices"), a subsidiary of the Company. HomeServices includes the
Company's real estate brokerage operations and offers integrated real estate
services in eleven states including residential brokerage, relocation, title,
abstract and mortgage services. On October 18, 1999, the Company closed on its
initial public offering of 3.25 million shares of common stock of HomeServices
at $15 per share. HomeServices sold 2.19 million newly issued shares and the
Company, the selling stockholder, sold 1.06 million of its HomeServices shares
in the offering. The offering reduced the Company's ownership in HomeServices to
approximately 65%.

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<PAGE>

Northern

The operations of Northern Electric plc ("Northern"), an indirect wholly owned
subsidiary of the Company, consist primarily of the distribution and supply of
electricity, supply of natural gas and other auxiliary businesses in the United
Kingdom. Northern's operations are seasonal in nature with a disproportionate
percentage of revenues and earnings historically being earned in the Company's
first and fourth quarters.

Northern receives electricity from the national grid transmission system and
distributes it to customers' premises using its network of transformers,
switchgear and cables. Substantially all of the customers in Northern's
authorized area are connected to Northern's network and can only be delivered
electricity through Northern's distribution system, regardless of whether it is
supplied by Northern's own supply business or by other suppliers, thus providing
Northern with distribution volume that is stable from year to year. Northern
charges access fees for the use of the distribution system. The prices for
distribution are controlled by a prescribed formula that limits increases (and
may require decreases) based upon the rate of inflation in the United Kingdom
and other regulatory action.

On December 2, 1999, the United Kingdom's Office of Gas and Electricity Markets
("Ofgem") issued its final proposals for regulated revenue reduction for the
distribution business of Northern to be effective from April 1, 2000. The report
proposed revenue reductions for all public electricity supply companies in Great
Britain including a reduction of 24% (equivalent to approximately $76 million
for a full year) for Northern. The proposals have been accepted by the Company.
To mitigate the effects of the revenue reduction, Northern is in the process of
implementing a series of cost reduction initiatives including a redundancy
program which will result in 500 employees leaving Northern.

Northern's supply business primarily involves the bulk purchase of electricity,
through a central pool, and subsequent resale to individual customers. The
supply business generally is a high volume business which tends to operate at
lower profitability levels than the distribution business. Prior to November 4,
1998, Northern was the exclusive supplier of electricity to premises in its
authorized area, except where the maximum demand of a customer was greater than
100kW. Beginning November 4, 1998, liberalization of the entire market in
Northern's area commenced in stages with complete liberalization achieved in
Northern's authorized area by the end of April 1999. In the market between 100kW
and 1MW of electrical demand, Northern is now one the largest electricity
suppliers in the U.K. market. As of December 31, 1999, Northern supplied
electricity to 1,339,000 customers.

Also, on December 2, 1999, Ofgem issued its final proposals for electricity
supply prices for the two years ended March 31, 2002. The proposals which have
been accepted by the Company relate mainly to domestic customers in Northern's
authorized area and will lead to a price reduction of approximately 11% in real
terms with effect from April 1, 2000.

Northern also competes to supply gas inside and outside its authorized area. In
the residential market Northern currently supplies gas to approximately 570,000
customers and is now the fourth largest gas supplier of the new entrants in the
U.K. residential market.

CalEnergy

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 Plants to CE Generation. For purposes of consistent
presentation, plant capacity factors for Vulcan, Hoch (Del Ranch), Elmore and
Leathers (collectively the "Partnership Projects") are based on capacity amounts
of 34, 38, 38, and 38 net MW, respectively, and for Salton Sea I, Salton Sea II,
Salton Sea III and Salton Sea IV plants (collectively the "Salton Sea Projects")
are based on capacity amounts of 10, 20, 49.8 and 39.6 net MW, respectively (the
Partnership Projects and the Salton Sea Projects are collectively referred to as
the "Imperial Valley Projects"). Plant capacity factors for Saranac, Power
Resources, NorCon and Yuma (collectively the "Gas Plants") are based on capacity
amounts of 240, 200, 80, and 50

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<PAGE>

net MW, respectively. Each plant possesses an operating margin that 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 between
calendar quarters, under normal operating conditions.

Due to the sale of 50% of its interests in CE Generation, the Company has
accounted for CE Generation as an equity investment beginning March 3, 1999.
Prior to that date, CE Generation results were fully consolidated.

The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong Projects
(collectively, the "Philippine Projects"), which are geothermal power plants
located on the island of Leyte in the Philippines. For purposes of consistent
presentation, capacity amounts for Upper Mahiao, Malitbog and Mahanagdong
(collectively, the "Philippine Projects") are 119, 216 and 165 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 between
calendar quarters, under normal operating conditions.

On February 26, 1999, the Company closed the sale of all of its ownership
interests in the Navy I, Navy II and BLM, collectively the Coso Joint Ventures,
to Caithness Energy, LLC ("Caithness"). The price included $205 million in cash
and $5 million in contingent payments.

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.

As a result of the Berkshire transaction, the MidAmerican Merger and the sales
of Coso and an interest in CE Generation, the Company's future results will
differ significantly from the Company's historical results.

Berkshire Transaction

On October 24, 1999, the Company and entities representing an investor group
comprised of Berkshire Hathaway Inc. ("Berkshire Hathaway"), Walter Scott, Jr.,
a director of the Company, and David L. Sokol, Chairman and Chief Executive
Officer of the Company, executed a definitive agreement and plan of merger
whereby the investor group would acquire all of the outstanding common stock of
the Company for $35.05 per share in cash, representing a total purchase price of
approximately $2.2 billion, including transaction costs. The Berkshire
Transaction closed on March 14, 2000 and Berkshire Hathaway invested
approximately $1.24 billion in common stock and convertible preferred stock and
approximately $455 million in nontransferable trust preferred stock. Mr. Scott,
Mr. Sokol and Gregory E. Abel, Chief Operating Officer of the Company,
contributed cash and current securities of the Company having a value of
approximately $310 million. The remaining purchase price was funded with the
Company's cash. Berkshire Hathaway owns not more than 9.9% of the voting stock,
Mr. Scott owns approximately 86% of the voting stock, Mr. Sokol owns
approximately 3% of the voting stock and Mr. Abel owns approximately 1% of the
voting stock.

The Company incurred approximately $6.7 million of non-recurring costs in 1999,
related to the Berkshire transaction, which were expensed.

Acquisitions/Dispositions

MidAmerican Merger

On August 11, 1998, the Company entered into an Agreement and Plan of Merger
with MHC. The MidAmerican Merger closed on March 12, 1999 and the Company paid
$27.15 in cash for each outstanding share of MHC common stock for a total of
approximately $2.42 billion in a merger, pursuant to which MHC became an
indirect

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<PAGE>

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 MidAmerican Merger has been accounted for as a purchase business combination
and as such the results of operations of the Company include the results of MHC
beginning March 12, 1999.

Qualified Facilities Disposition

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. To accomplish this disposition, the following events occurred in the
first quarter of 1999:

On February 26, 1999, the Company closed the sale of all of its ownership
interests in the Coso Joint Ventures to Caithness for $205 million in cash.

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 Projects and Gas Plants 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 in 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 an aggregate
consideration of approximately $245 million in cash, $6.5 million in contingent
payments and $23.5 million in equity commitments.

The sales of the qualified facilities resulted in a net non-recurring pre-tax
gain of $20.2 million and an after-tax gain of approximately $12.4 million or
$0.17 per diluted share.

McLeod

On May 18, 1999, the Company announced the sale of approximately 6.74 million
shares of McLeodUSA ("McLeod") Class A common stock, through a secondary
offering by McLeod, at $55.625 per share. Proceeds from the sale were
approximately $375 million, with a resulting pre-tax gain to the Company of
approximately $78.2 million and an after-tax gain of approximately $47.1 million
or $0.65 per diluted share.

HomeServices

On October 18, 1999, the Company announced that HomeServices, a subsidiary of
the Company, closed its initial public offering of 3,250,000 shares of common
stock at $15 per share. HomeServices sold 2,187,500 shares and the Company, the
selling stockholder, sold 1,062,500 shares in the offering. HomeServices is the
surviving entity of a merger with MidAmerican Realty Services.

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 geothermal steam fields 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 ("ESCs") with both Pertamina and P.T. PLN
(Persero) ("PLN"), the Indonesian national electric utility. The Government of
Indonesia provided sovereign performance undertakings of the obligations under
the joint operating and "take-or-pay" contracts.

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<PAGE>

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) created significant uncertainty as to
whether PLN and the Indonesian government would honor their contractual
obligations to the Indonesian Subsidiaries.

In 1997, the Company recorded a non-recurring charge of $87 million representing
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 charge of $87 million represented the amount by which the carrying amount of
such assets exceeded the estimated 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.

On or about August 14, 1998, the Company, through the Indonesian Subsidiaries,
began arbitration proceedings against PLN in connection with the HCE's and PPL's
geothermal power projects in Indonesia, the Dieng Project and the Patuha
Project. An arbitral tribunal found that PLN had materially breached the
provisions of the ESCs between PLN and both HCE and PPL, and awarded HCE
approximately $391.7 million and PPL $180.6 million, and ordered PLN to pay
these amounts immediately.

Following PLN's failure to pay such amounts, HCE and PPL demanded payment
pursuant to the sovereign performance undertakings issued by the Minister of
Finance ("MOF") on behalf of the Republic of Indonesia ("ROI") and following the
ROI's failure to pay brought an arbitration against the ROI for breach of those
undertakings. A final award was issued by an international arbitration panel in
the ROI arbitration on October 15, 1999, which found that the ROI materially
breached its performance undertakings and violated international law and the ROI
was required to pay HCE and PPL an aggregate amount of approximately $575
million.

The Company carried political risk insurance on its investment in HCE and PPL
through OPIC, an agency of the U.S. Government, as well as through private
market insurers. Such insurance covered expropriation of the Company's
investment in HCE and PPL, as well as material breaches by PLN of the ESCs and
by the ROI of its performance undertakings. On November 18, 1999, the Company
received payment from OPIC and the private market insurers totaling $290 million
under its political risk insurance policies, reflecting the return of its equity
investment less policy deductibles. Due primarily to the timing of the receipt
of the proceeds, the Company recorded a pre-tax gain of approximately $40.3
million on the insurance proceeds and an additional tax benefit of $17.7 million
for an after-tax gain of $58.0 million, or $0.81 per diluted share.

Results of Operations For The Years Ended December 31, 1999, 1998 and 1997

Operating revenue increased in the year ended December 31, 1999 to $4,128.7
million from $2,555.2 million for the same period in 1998, a 61.6% increase.
Northern's operating revenue increased in the year ended December 31, 1999 to
$2,072.2 million from $1,823.9 million for the same period in 1998, primarily
due to higher volumes of gas supplied as well as higher electricity supply
revenues. The MidAmerican Merger added $1,687.9 million in the period from March
12, 1999 through December 31, 1999. These increases were partially offset by the
sales of Coso and reporting the 50% interest in CE Generation using the equity
method beginning March 3, 1999.

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.

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<PAGE>

The following data represents the supply and distribution operations in the
U.K.:

Year Ended December 31,
-----------------------------
1999 1998 1997
---- ---- ----

Electricity Supplied (GWh).............. 17,984 15,313 14,378

Electricity Distributed (GWh)........... 15,943 15,904 15,714

Gas Supplied (Therms in millions) ...... 484.2 359.5 74.5

The increases in electricity supplied for the year ended December 31, 1999 from
the same period in 1998 are due primarily to the increase in supply volumes for
customers outside of the franchise area. The increases in electricity
distributed for the year ended December 31, 1999 from the same period in 1998
are due to changes in demand in the franchise area. The increases in gas
supplied in 1999 from 1998 reflects the increased volume as the domestic gas
supply business in the U.K. opened up to competition as a result of regulatory
changes and the successful dual fuel marketing campaign.

The following data represents sales from utility operations for MEC. The
financial results of MEC are consolidated with the Company beginning on March
12, 1999.

Year Ended December 31,
-----------------------------
1999 1998 1997
---- ---- ----

Electric Retail Sales (GWh)............. 16,007 16,088 15,666

Electric Sales for Resale (GWh)......... 7,168 6,186 6,987

Gas Throughput (Therms in millions)..... 812 820 938

Interest and other income increased for the year ended December 1999 to $131.3
million from $127.5 million in the same period in 1998. The addition of MHC
amounts following the MidAmerican Merger and the addition of equity income from
CE Generation accounted for the increase partially offset by reduction of
operator fees related to the qualified facilities that we sold in 1999 .
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.

The gains on non-recurring items of $138.7 million in 1999 represent the pre-tax
gain on the sale of the qualified facilities of $20.2 million, the pre-tax gain
on the sale of McLeod common stock of $78.2 million and the pre-tax gain on the
Indonesia settlement of $40.3 million.

Cost of sales increased in the year ended December 1999 to $2,143.9 million from
$1,258.5 million from the same period in 1998, a 70.4% increase. The increase is
primarily due to higher volumes of gas and electricity supplied at Northern and
the MidAmerican Merger. The acquisition of MHC added $655.2 million in the
period March 12, 1999 through December 31, 1999. 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.

Operating expense increased in the year to date ended December 1999 to $989.6
million from $471.4 million for the same period in 1998, a 109.9% increase. The
MidAmerican Merger added $597.3 million in the period from March 12, 1999
through December 31, 1999, partially offset by the sales of Coso and an interest
in CE Generation.

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Operating expense increased to $471.4 million in 1998 from $398.5 million in
1997, an increase of 18.3%. 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.

Depreciation and amortization increased in the year to date December 1999 to
$427.7 million from $333.4 million in the same period in 1998, a 28.3% increase.
The MidAmerican Merger added $187.3 million in the period from March 12, 1999
through December 31, 1999, partially offset by the sales of Coso and the 50%
interest in CE Generation. 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 acquisition of KDG.

As a result of the acquisition of KDG, Casecnan is fully consolidated into the
Company's financial statements beginning January 2, 1998 and is no longer
recorded as an equity investment.

Interest expense, less amounts capitalized, increased in the year to date
December 1999 to $426.2 million from $347.3 million, a 22.7% increase. The
increase is primarily due to the MidAmerican Merger and the greater average
outstanding debt balances. Interest expense, less amounts capitalized, increased
in 1998 to $347.3 million from $251.3 million in 1997, a 38.2% increase. The
increase 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 losses on non-recurring items of $54.4 million in 1999 represent the pre-tax
loss of $47.7 million related to the costs associated with the reduction of
Northern's workforce and the $6.7 million of costs related to the Berkshire
transaction.

The non-recurring charge of $87 million in 1997 represented an asset valuation
impairment under Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets," relating to the Company's
assets in Indonesia. The charge included all reasonably estimated cash flows
associated with the Company's assets in Indonesia and gave effect to the
political risk insurance on such investments.

The provision for income taxes increased marginally to $93.5 million in 1999
from $93.3 million in 1998 and decreased from $99.0 million in 1997. The
decrease from 1997 to 1998 is due to lower pre-tax book income that resulted
from increased dividends on convertible preferred securities of subsidiary
trusts. After adjusting for the non-recurring gains and losses and the
deductible dividends on preferred securities, the effective tax rate was 38.7%,
39.5% and 38.0% in 1999, 1998 and 1997 respectively.

Minority interest consists of dividends on preferred securities of subsidiaries
and minority ownership of HomeServices. Minority interest increased in the year
ended December 1999 to $46.9 million from $41.3 million in the same period in
1998, a 13.6% increase. The increase is primarily due to the MidAmerican Merger
that has minority interests in the form of preferred stock outstanding. Minority
interest decreased to $41.3 million in 1998 from $46.0 million in 1997, a
decrease of 10.3%. 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.

Income before extraordinary items increased in the year ended December 1999 to
$216.7 million or $3.62 per share from $137.5 million or $2.29 per share in
1998, and $51.8 million or $0.77 per share in 1997. 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.

Due to the early retirements of the Senior Discount Notes, the Limited Recourse
Notes and the 9.5% Senior Notes, the Company recorded extraordinary losses of
approximately $49.4 million, net of tax, in the year ended December 31, 1999.

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During 1998, the Company recognized an extraordinary loss of $7.1 million, net
of tax, related to the 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 1997 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.

The Company's unrestricted cash and cash equivalents were $316.3 million at
December 31, 1999 as compared to $1,606.1 million at December 31, 1998. The
majority of this decrease was due to the cash used to acquire MHC and the early
retirement of the Senior Discount Notes, the Limited Recourse Notes and the 9.5%
Senior Notes partially offset by the sales of McLeod common stock, the Qualified
Facilities and the insurance proceeds on Indonesia. In addition, the Company
recorded separately restricted cash and investments of $291.7 million and $637.6
million at December 31, 1999 and December 31, 1998, respectively. The restricted
cash balance as of December 31, 1999 is comprised primarily of amounts deposited
in restricted accounts from which the Company will fund the various projects
under construction, and the Philippine Projects' cash reserves for the debt
service reserve funds.

Berkshire Transaction

On October 24, 1999, the Company and entities representing an investor group
comprised of Berkshire Hathaway Inc. ("Berkshire Hathaway"), Walter Scott, Jr.,
a director of the Company, and David L. Sokol, Chairman and Chief Executive
Officer of the Company, executed a definitive agreement and plan of merger
whereby the investor group would acquire all of the outstanding common stock of
the Company for $35.05 per share in cash, representing a total purchase price of
approximately $2.2 billion, including transaction costs. The Berkshire
Transaction closed on March 14, 2000 and Berkshire Hathaway invested
approximately $1.24 billion in common stock and convertible preferred stock and
approximately $455 million in nontransferable trust preferred stock. Mr. Scott,
Mr. Sokol and Gregory E. Abel, Chief Operating Officer of the Company
contributed cash and current securities of the Company having a value of
approximately $310 million. The remaining purchase price was funded with the
Company's cash. Berkshire Hathaway owns not more than 9.9% of the voting stock,
Mr. Scott owns approximately 86% of the voting stock, Mr. Sokol owns
approximately 3% of the voting stock and Mr. Abel owns approximately 1% of the
voting stock.

The Company incurred approximately $6.7 million of non-recurring costs in 1999,
related to the Berkshire tranaction, which were expensed.

Financing Activities

The remaining outstanding Senior Discount Notes of $369.5 million were redeemed
on January 15, 1999 at a redemption price of 105.125% plus accrued interest.

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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 approximately $195.8 million of principal which were paid on
March 3, 1999, at a redemption price of 110.025% plus accrued interest.

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

On May 18, 1999, CalEnergy Capital Trust, a subsidiary of the Company, effected
the conversion of $103.9 million of 6 1/4% Convertible Preferred Securities into
approximately 3.5 million shares of common stock of the Company. The securities
were converted at a rate of 1.6728 shares of common stock of the Company for
each security, equivalent to a conversion price of $29.89 per share of Company
common stock.

The Company has redeemed substantially all of the $225 million in principal
value of the 9.5% Senior Notes at an aggregate price of $247.6 million
throughout the year ended December 31, 1999.

Minerals Extraction

The Company developed and owns the rights to proprietary processes 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 Projects. 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 as an extraction project. Silica is used
as a filler for such products as paint, plastics and high temperature cement.

CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company, is
constructing the Zinc Recovery Project that will recover zinc from the
geothermal brine (the "Zinc Recovery Project"). Facilities will be installed
near the Imperial Valley Projects 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
tons per year and is scheduled to commence commercial operation in mid-2000. In
September 1999, CalEnergy Minerals LLC entered into a sales agreement whereby
all zinc produced by the Zinc Recovery Project will be sold to Cominco, LTD. The
initial term of the agreement expires in December 2005.

Casecnan

CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE
Casecnan") which at completion of the Casecnan Project is expected to be at
least 70% indirectly owned by the Company, is constructing 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.

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CE Casecnan has 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.

Cordova

Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company, has commenced construction of a 537 MW gas-fired
power plant in the Quad Cities, Illinois area (the "Cordova Project"). Cordova
Energy has entered into an engineering, procurement and construction contract
with Stone & Webster Engineering Corporation ("SWEC") to build the project.
Total project costs are estimated to be approximately $288.9 million. The
Company has also entered into a power sales agreement with a unit of El Paso
Energy Corporation ("El Paso"). Under the power sales agreement, El Paso will
purchase all the capacity and energy from the project until December 31, 2019.
However, Cordova Energy has the option to elect on an annual basis to retain up
to 50% of the project output for sales to others. The construction of the
Cordova Project is expected to be completed in mid-2001.

On September 10, 1999 Cordova Funding Corporation ("Cordova Funding"), a wholly
owned subsidiary of the Company, closed the $225 million aggregate principal
amount financing for the construction of the Cordova Project. As part of the
financing, approximately $93.5 million of 8.64% Series A-1 Senior Secured Bonds
due in 2019 were issued. An additional $31.3 million of 8.79% Series A-2 Senior
Secured Bonds were issued on December 15, 1999. Additional Series A Senior
Secured Bonds will be issued as required to fund construction. Cordova Funding
will loan the proceeds to Cordova Energy as required. The Company has incurred
$80.0 million of such costs through December 31, 1999. Total equity funding is
expected to be approximately $63.9 million.

Evolution of the Domestic Utility Industry

The U.S. utility industry continues to evolve into an increasingly competitive
environment. In virtually every region of the country, legislative and
regulatory actions are being taken which result in customers having more choices
in their energy decisions.

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In the electric industry, the traditional vertical integration of generation,
delivery and marketing is being unbundled, with the generation and marketing
functions becoming deregulated. For local gas distribution businesses, the
supply, local delivery and marketing functions are similarly being separated and
opened to competitors for all classes of customers. While retail electric
competition is presently not permitted in Iowa, MEC's primary market,
legislation to do so was introduced in the Iowa legislature in the last session.
While this legislation has not passed, it is being considered again by the Iowa
legislature in 2000. Deregulation of the gas supply function related to small
volume customers is also being considered by the Iowa Utilities Board ("IUB").
MEC is actively participating in the legislative and regulatory processes.

The generation and retail portions of MEC's electric business will be most
affected by competition. The introduction of competition in the wholesale market
has resulted in a proliferation of power marketers and a substantial increase in
market activity. As retail choice evolves, competition from other traditional
utilities, power marketers and customer-owned generation could put pressure on
utility margins.

During the transition to full competition, increased volatility in the
marketplace can be expected. With the elimination of the energy adjustment
clause in Iowa, MEC is financially exposed to movements in energy prices.
Although MEC has sufficient low cost generation under typical operating
conditions for its retail electric needs, a loss of adequate generation by MEC
at a time of high market prices could subject MEC to losses on its energy sales.

Domestic Legislative and Regulatory Evolution

In December 1997, the Governor of Illinois signed into law a bill to restructure
Illinois' electric utility industry and transition it to a competitive market.
Under the law, beginning October 1, 1999, larger non-residential customers in
Illinois and 33% of the remaining non-residential Illinois customers are 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.

Accounting Effects of Industry Restructuring

A possible consequence of competition in the utility industry is that SFAS 71
may no longer apply. SFAS 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 majority of MEC's electric and gas
utility operations currently meet the criteria required by SFAS 71, but its
applicability is periodically reexamined. On December 16, 1997, MEC's generation
operations serving Illinois were no longer subject to the provisions of SFAS 71
due to passage of industry restructuring legislation in Illinois. Thus, in 1997
MEC was required to write off the regulatory assets and liabilities from its
balance sheet related to its Illinois generation operations. The net amount of
such write-offs was not material. If other portions of its utility operations no
longer meet the criteria of SFAS 71, MEC could be required to write off the
related regulatory assets and liabilities from its balance sheet, and thus, a
material adjustment to earnings in that period could result if regulatory assets
are not recovered in transition provisions of any resulting legislation. As of
December 31, 1999, the Company had $278.8 million of regulatory assets on its
consolidated balance sheet.

Domestic Rate Matters: Electric

Through several steps from mid-1997 to the end of 1998, electric prices for Iowa
industrial customers were reduced by an amount which had a $6 million annual
impact on revenues, and electric prices for Iowa commercial customers were
reduced by an amount which had a $4 million annual impact on revenues. The
reductions were achieved through a retail access pilot project, negotiated
individual electric contracts and a $1.5 million tariffed rate reduction for
certain non-contract commercial customers.

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The negotiated electric 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. The vast majority of the contracts are for terms of seven years or less,
although, some large customers have agreed to ten-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 MEC incurs to fulfill these
contracts will vary. MEC presently intends to manage this risk through hedging
and other similar arrangements. On an aggregate basis the annual revenues under
contract are approximately $180 million.

Under a 1997 pricing plan settlement agreement resulting from an IUB rate
proceeding, if MEC's annual Iowa electric jurisdictional return on common equity
exceeds 12%, then earnings above the 12% level will be shared equally between
customers and MEC. If the return exceeds 14%, then two-thirds of MEC's share of
those earnings above the 14% level will be used for accelerated recovery of
certain regulatory assets. The pricing plan settlement agreement precludes MEC
from filing for increased rates prior to 2001 unless the return falls below 9%.
Other parties signing the agreement are prohibited from filing for reduced rates
prior to 2001 unless the return, after reflecting credits to customers, exceeds
14%. On April 14, 1999, the Iowa Utilities Board approved, subject to additional
refund, MEC's calculation of the 1998 return on common equity. During the second
quarter of 1999, MEC credited $2.2 million to its Iowa non-contract customers
related to the return calculation for 1998. The agreement also eliminated MEC's
energy adjustment clause, and, as a result, the cost of fuel is not directly
passed on to customers. In 1999, MEC accrued $15.0 million for customer credits
relating to 1999 operations.

Environmental Matters

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

MEC has evaluated or is evaluating 27 properties which were, at one time, sites
of gas manufacturing plants in which it may be a potentially responsible party.
The purpose of these evaluations is to determine whether waste materials are
present, whether the materials constitute an environmental or health risk, and
whether MEC has any responsibility for remedial action. MEC's estimate of the
probable costs for these sites as of December 31, 1999, was $28 million. This
estimate has been recorded as a liability and a regulatory asset for future
recovery through the regulatory process.

Although the timing of potential incurred costs and recovery of costs in rates
may affect the results of operations in individual periods, management believes
that the outcome of these issues will not have a material adverse effect on the
Company's financial position or results of operations.

On July 18, 1997, the EPA adopted revisions to the National Ambient Air Quality
Standards for ozone and a new standard for fine particulate matter. Based on
data to be obtained from monitors located throughout the states, the EPA will
make a determination of whether the states have any areas that do not meet the
air quality standards (i.e., areas that are classified as nonattainment). If a
state has area(s) classified as nonattainment area(s), the state is required to
submit a State Implementation Plan specifying how it will reach attainment of
the standards through emission reductions or other means.

In May 1999, the U.S. Court of Appeals for the District of Columbia Circuit
remanded the standards adopted in July 1997 back to the EPA indicating the EPA
had not expressed sufficient justification for the basis of establishing the
standards and ruling that the EPA has exceeded its constitutionally-delegated
authority in setting the standards. The EPA's appeal of the court's ruling to
the full panel of the U.S. Court of Appeals for the District of Columbia Circuit
was denied. As a result of the court's initial decision and the current status
of the standards, the impact of any new standards on the Company is currently
unknown. If the EPA successfully appeals the court's decision, however, and

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the new standards are implemented, then MEC's fossil fuel generating stations
may be subject to emission reductions if the stations are located in
nonattainment areas. As part of an overall state plan to achieve attainment of
the standards, MEC could be required to install control equipment on its fossil
fuel generating stations or decrease the number of hours during which these
stations operate. The degree to which MEC may be required to install control
equipment or decrease operating hours under a nonattainment scenario would be
determined by the state's assessment of ME's relative contribution, along with
other emission sources, to the nonattainment status. The installation of control
equipment would result in increased costs to MEC. A decrease in the number of
hours during which the affected stations operate would decrease the revenues of
the Company.

Nuclear Decommissioning

Each licensee of a nuclear facility is required to provide financial assurance
for the cost of decommissioning its licensed nuclear facility. In general,
decommissioning of a nuclear facility means to safely remove the facility from
service and restore the property to a condition allowing unrestricted use by the
operator. Based on information presently available, the Company expects to
contribute approximately $42 million during the period 2000 through 2004 to an
external trust established for the investment of funds for decommissioning Quad
Cities Station. Approximately 65% of the trust's funds are now invested in
domestic corporate debt and common equity securities. The remainder is invested
in investment grade municipal and U.S. Treasury bonds.

In addition, MEC makes payments to the Nebraska Public Power District ("NPPD")
related to decommissioning Cooper. These payments are reflected in other
operating expense in the consolidated statements of operations. NPPD estimates
call for MEC to pay approximately $57 million to NPPD for Cooper decommissioning
during the period 2000 through 2004. NPPD invests the funds predominately in
U.S. Treasury Bonds and other U.S. Government securities. Approximately 20% was
invested in domestic corporate debt. MEC's obligation for Cooper decommissioning
may be affected by the actual plant shutdown date and the status of the power
purchase contract at that time. In July 1997, NPPD filed a lawsuit in United
States District Court for the District of Nebraska naming MEC as the defendant
and seeking a declaration of MEC's rights and obligations in connection with
Cooper nuclear decommissioning funding.

Cooper and Quad Cities Station decommissioning costs charged to Iowa customers
are included in base rates, and recovery of increases in those amounts must be
sought through the normal ratemaking process. Cooper decommissioning costs
charged to Illinois customers are recovered through a rate rider on customer
billings.

Securitization of Accounts Receivable

In December 1998, Northern entered into a revolving receivable purchase
agreement with Kitty Hawk Funding Corporation ("Kitty Hawk"), an unaffiliated
special purpose entity established to purchase accounts receivable. The
agreement, which expires annually, was renewed in December 1999, allows Northern
to sell all of its rights, title and interest in the majority of its billed
electricity accounts receivable and to borrow against its unbilled electricity
accounts receivable. In March 1999, Northern received $161 million in cash
associated with the agreement. As of December 31, 1999, approximately $19
million was accounted for as a loan.

Development Activity

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

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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 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 the value of the project being
developed, which the Company may not be fully capable of insuring against. The
uncertainty of the legal environment in certain foreign countries in which the
Company may develop or acquire projects could make it more difficult for the
Company to enforce its rights under agreements relating to such projects. In
addition, the laws and regulations of certain countries may limit the ability of
the Company to hold a majority interest in some of the projects that it may
develop or acquire. The Company's international projects may, in certain cases,
be terminated by a government. 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.

New Accounting Pronouncement

In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("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
2001. 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, 1999, the Company had fixed-rate long-term debt,
Company-obligated mandatorily redeemable convertible preferred securities of
subsidiary trusts and subsidiary-obligated mandatorily redeemable preferred
securities of subsidiary trusts of $5,993.2 million in principal amount and
having a fair value of $5,825.7 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 $281 million if interest rates were to increase by 10%
from their levels at December 31, 1999. 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, 1999, the Company had floating-rate obligations of $670.5
million that expose the Company to the risk of increased interest expense in the
event of increases in short-term interest rates. If the floating rates were to
increase by 10% from December 31, 1999 levels, the Company's consolidated
interest expense for unhedged floating-rate obligations would increase by
approximately $414,000 each month in which such increase continued based upon
December 31, 1999 principal balances.

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Currency Exchange Rate Risk

At December 31, 1999, CE Electric UK Funding Company had fixed-rate obligations
denominated in U.S. dollars that 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, 1999, these interest rate swap agreements had an
aggregate notional amount of $362 million, which the Company could terminate at
a cost of approximately $12.1 million. A decrease of 10% in the December 31,
1999 rate of exchange of Sterling to dollars would increase the cost of
terminating these swap agreements by approximately $54 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 that will
be subject to commodity 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 volumes covered by
the CFD.

Therefore, disclosure in respect to CFDs 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 terms. As
of December 31, 1999, the notional amount of executed CFDs was approximately
$639.2 million, representing approximately 12% of the expected or committed
transaction volumes through March 31, 2004. The fair value of these contracts
was approximately $(11.5) million discounted at 15%, based upon quoted market
prices at December 31, 1999. A hypothetical decrease of 10% in the market price
of electricity from the December 31, 1999 levels would decrease the fair value
of these contracts by approximately $54.7 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.

-57-
<PAGE>

As of December 31, 1999, the notional amount of outstanding forward purchase
contracts was approximately $226.8 million, representing approximately 13% of
expected sales through December 31, 2007. The fair value of such contracts was
approximately $(8.2) million discounted at 15%, based upon quoted market prices
at December 31, 1999. A hypothetical decrease of 10% in the market price of gas
from the December 31, 1999 levels would further decrease the fair value of these
contracts by approximately $17.2 million.

Forward-looking Statements

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,
Indonesia) 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.

-58-
<PAGE>
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>

AS OF DECEMBER 31,
---------------------------
1999 1998
------------ -----------

<S> <C> <C>
ASSETS
- ------
Current Assets:
Cash and investments ....................................... $ 316,327 $ 1,606,148
Restricted cash and short term investments ................. 36,294 29,395
Accounts receivable ........................................ 600,564 525,102
Other current assets ....................................... 185,128 141,721
------------ -----------
Total Current Assets ..................................... 1,138,313 2,302,366

Property, plant, contracts and equipment, net ................ 5,463,329 4,236,039
Excess of cost over fair value of net assets acquired, net ... 2,712,677 1,538,176
Regulatory assets ............................................ 278,757 --
Long-term restricted cash and investments..................... 255,440 608,176
Nuclear decommissioning trust fund
and other marketable securities ............................ 226,298 -
Equity investments ........................................... 208,023 125,036
Deferred charges, other investments and other assets ......... 483,515 293,731
------------ -----------
Total Assets ............................................... $ 10,766,352 $ 9,103,524
============ ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
Current Liabilities:
Accounts payable ........................................... $ 449,203 $ 305,720
Other accrued liabilities .................................. 458,667 252,751
Current portion of long-term debt .......................... 614,725 381,491
------------ -----------
Total Current Liabilities ................................ 1,522,595 939,962

Other long-term accrued liabilities .......................... 1,054,440 756,377
Parent company debt .......................................... 1,856,318 2,645,991
Subsidiary and project debt .................................. 3,642,703 2,712,319
Deferred income taxes ........................................ 902,868 543,391
------------ -----------
Total Liabilities ......................................... 8,978,924 7,598,040
------------ -----------

Deferred income .............................................. 65,509 58,468
Minority interest ............................................ 29,127 --
Company-obligated mandatorily redeemable convertible
preferred securities of subsidiary trusts .................. 450,000 553,930
Subsidiary-obligated mandatorily redeemable
preferred securities of subsidiary trusts .................. 101,598 --
Preferred securities of subsidiaries.......................... 146,606 66,033

Commitments and contingencies (Notes 17, 18 and 19)

Stockholders' Equity:
Preferred Stock - authorized 2,000 shares, no par value ...... -- --
Common stock - authorized 180,000 shares no par value;
82,980 shares issued, 59,944 and 59,605 shares outstanding,
at December 31, 1999 and 1998, respectively ................ -- --
Additional paid in capital ................................... 1,249,079 1,238,690
Retained earnings ............................................ 507,726 340,496
Accumulated other comprehensive income ....................... (12,029) 45
Treasury stock - 23,036 and 23,375 common shares at
December 31, 1999 and 1998, respectively, at cost .......... (750,188) (752,178)
------------ -----------
Total Stockholders' Equity ................................ 994,588 827,053
------------ -----------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ................... $ 10,766,352 $ 9,103,524
============ ===========
</TABLE>

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

-59-
<PAGE>

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>

YEAR ENDED DECEMBER 31,
----------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
REVENUE:
Operating revenue ................................... $ 4,128,737 $ 2,555,206 $ 2,166,338
Interest and other income ........................... 131,342 127,505 104,573
Gains on non-recurring items ........................ 138,704 -- --
----------- ----------- -----------
TOTAL REVENUES ........................................ 4,398,783 2,682,711 2,270,911
----------- ----------- -----------

COSTS AND EXPENSES:
Cost of sales ....................................... 2,143,891 1,258,539 1,055,195
Operating expense ................................... 989,551 471,405 398,538
Depreciation and amortization ....................... 427,690 333,422 276,041
Loss on equity investment in Casecanan .............. -- -- 5,972
Interest expense .................................... 496,578 406,084 296,364
Less interest capitalized ........................... (70,405) (58,792) (45,059)
Losses on non-recurring items........................ 54,409 -- 87,000
----------- ----------- -----------
TOTAL COSTS AND EXPENSES .............................. 4,041,714 2,410,658 2,074,051
----------- ----------- -----------

Income before provision for income taxes .............. 357,069 272,053 196,860
Provision for income taxes ............................ 93,475 93,265 99,044
----------- ----------- -----------

Income before minority interest ....................... 263,594 178,788 97,816
Minority interest ..................................... 46,923 41,276 45,993
----------- ----------- -----------

INCOME BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE.. 216,671 137,512 51,823

Extraordinary item, net of tax ........................ (49,441) (7,146) (135,850)
Cumulative effect of change in accounting
principle, net of tax ............................... -- (3,363) --
----------- ----------- -----------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS .... $ 167,230 $ 127,003 $ (84,027)
=========== =========== ===========

INCOME PER SHARE BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE - BASIC .................................. $ 3.62 $ 2.29 $ 0.77
Extraordinary item .................................... (.83) (.12) (2.02)
Cumulative effect of change in accounting principle ... -- (.06) --
----------- ----------- -----------
INCOME (LOSS) PER SHARE - BASIC ....................... $ 2.79 $ 2.11 $ (1.25)
=========== =========== ===========
INCOME PER SHARE BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE - DILUTED ................................ $ 3.28 $ 2.15 $ 0.75
Extraordinary item .................................... (.69) (.10) (1.97)
Cumulative effect of change in accounting principle ... -- (.04) --
----------- ----------- -----------
INCOME (LOSS) PER SHARE - DILUTED ..................... $ 2.59 $ 2.01 $ (1.22)
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.

-60-

<PAGE>

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
For the Three Years Ended December 31, 1999
(In thousands)
<TABLE>
<CAPTION>

ADDITIONAL
COMMON
OTHER STOCK
OUTSTANDING ADDITIONAL COMPRE- & OPTIONS UNEARNED
COMMON COMMON PAID-IN RETAINED HENSIVE SUBJECT TO TREASURY COMPEN-
SHARES STOCK CAPITAL EARNINGS INCOME REDEMPTION STOCK SATION TOTAL
----------- ------ ---------- -------- -------- ---------- --------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE DECEMBER 31, 1996 63,448 $ -- $ 567,870 $297,520 $ 29,658 $ -- $ (8,787) $(5,471) $880,790

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

Equity offering 19,100 -- 698,604 -- -- -- -- -- 698,604
Exercise of stock options and
other equity transactions 396 -- (2,747) -- -- -- 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 -- 1,266,683 213,493 (3,589) (654,736) (56,525) -- 765,326

Net income -- -- -- 127,003 -- -- -- -- 127,003
Other Comprehensive Income:
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 -- 1,238,690 340,496 45 -- (752,178) -- 827,053

Net income -- -- -- 167,230 -- -- -- -- 167,230
Other Comprehensive Income
Foreign currency translation
adjustment * -- -- -- -- (12,047) -- -- -- (12,047)
Unrealized losses on securities,
net of tax of $14 -- -- -- -- (27) -- -- -- (27)
--------
Comprehensive income 155,156

Issuance of stock by subsidiary -- -- 9,113 -- -- -- -- -- 9,113
Exercise of stock options and
other equity transactions 238 -- (2,628) -- -- -- 7,779 -- 5,151
Purchase of treasury stock (3,376) -- -- -- -- -- (104,847) -- (104,847)
Conversion of TIDES I 3,477 -- 2,845 -- -- -- 99,058 -- 101,903
Tax benefit from stock plan -- -- 1,059 -- -- -- -- -- 1,059

__________________________________________________________________________________________________________________________________
BALANCE DECEMBER 31, 1999 59,944 $ -- $1,249,079 $507,726 $(12,029) $ -- $(750,188) $ -- $ 994,588
__________________________________________________________________________________________________________________________________
* Foreign currency translation adjustment has no tax effect

</TABLE>

The accompanying notes are an integral part of these financial statements

-61-
<PAGE>

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>

YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ...................................................... $ 167,230 $ 127,003 $ (84,027)
Adjustments to reconcile net cash flow from operating activities:
Gains on non-recurring items ........................................ (138,704) -- --
Non-recurring charge-asset valuation impairment ..................... -- -- 87,000
Extraordinary item, net of tax ...................................... 49,441 7,146 --
Cumulative effect of change in accounting principle ................. -- 3,363 --
Depreciation and amortization ....................................... 363,737 290,794 239,234
Amortization of excess of cost over fair value of net assets acquired 63,953 42,628 36,807
Amortization of deferred financing and other costs .................. 18,181 21,723 33,792
Provision for deferred income taxes ................................. (56,590) 34,332 55,584
Distributions in excess of (less than) income on equity investments . (22,796) 6,171 7,892
Income (loss) applicable to minority interest ....................... 14,240 5,313 (35,387)
Changes in other items:
Accounts receivable ............................................... 61,209 (135,124) (34,146)
Accounts payable, accrued liabilities and deferred income ......... 32,917 (41,803) 29,799
----------- ----------- -----------
NET CASH FLOWS FROM OPERATING ACTIVITIES ............................... 552,818 361,546 336,548
----------- ----------- -----------

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of MidAmerican, Kiewit's Interests and Northern,
net of cash acquired ................................................ (2,501,425) (500,916) (632,014)
Proceeds from sale of QF's, net of cash disposed ....................... 365,074 -- --
Proceeds from Indonesia settlement ..................................... 290,000 -- --
Purchase of marketable securities ...................................... (92,523) -- --
Proceeds from sale of marketable securities ............................ 498,676 -- --
Capital expenditures relating to operating projects .................... (331,337) (227,071) (194,224)
Philippine construction ................................................ (62,059) (112,263) (27,334)
Acquisition of U.K. gas assets ......................................... (72,280) (35,677) --
Domestic construction and other development costs ...................... (180,683) (119,916) (159,091)
Decrease (increase) in restricted cash and investments ................. 199,588 20,568 (116,668)
Other .................................................................. (58,263) (32,505) 63,270
----------- ----------- -----------
NET CASH FLOWS FROM INVESTING ACTIVITIES ............................... (1,945,232) (1,007,780) (1,066,061)
----------- ----------- -----------

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common and treasury stock
and exercise of stock options ...................................... 5,482 3,412 703,624
Proceeds from convertible preferred securities of subsidiary trusts .... -- -- 450,000
Proceeds from issuance of parent company debt .......................... -- 1,502,243 350,000
Repayment of parent company debt ....................................... (853,420) (167,285) (100,000)
Net proceeds from revolver ............................................. -- -- (95,000)
Proceeds from subsidiary and project debt .............................. 1,429,856 464,974 795,658
Repayments of subsidiary and project debt .............................. (369,016) (255,711) (271,618)
Deferred charges relating to debt financing ............................ 7,761 (47,205) (48,395)
Purchase of treasury stock ............................................. (104,847) (724,791) (55,505)
Other .................................................................. (1,176) 21,701 13,142
----------- ----------- -----------
NET CASH FLOWS FROM FINANCING ACTIVITIES ............................... 114,640 797,338 1,741,906
----------- ----------- -----------
Effect of exchange rate changes ........................................ (12,047) 3,634 (33,247)
----------- ----------- -----------
Net increase (decrease) in cash and cash equivalents ................... (1,289,821) 154,738 979,146
Cash and cash equivalents at beginning of year ......................... 1,606,148 1,451,410 472,264
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR ............................... $ 316,327 $ 1,606,148 $ 1,451,410
=========== =========== ===========
Supplemental Disclosures:
Interest paid, net of amount capitalized ............................... $ 439,894 $ 341,645 $ 316,060
=========== =========== ===========
Income taxes paid ...................................................... $ 130,875 $ 53,609 $ 44,483
=========== =========== ===========
</TABLE>

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

-62-
<PAGE>
MIDAMERICAN ENERGY HOLDINGS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BUSINESS

MidAmerican Energy Holdings Company, the successor to CalEnergy Company, Inc.
(the "Company" or "MEHC"), is a United States-based privately owned global
energy company with publicly traded fixed income securities which generates,
distributes and supplies energy to utilities, government entities, retail
customers and other customers located throughout the world. Through its
subsidiaries the Company is organized and managed on three separate platforms:

MIDAMERICAN

The MidAmerican Platform consists primarily of the Company's ownership in
MidAmerican Energy Company ("MEC"). MEC is the largest energy company
headquartered in Iowa and is a regulated public utility principally engaged in
the business of generating, transmitting, distributing and selling electric
energy and in distributing, selling and transporting natural gas. MEC
distributes electricity at retail in Iowa, Illinois, and South Dakota. It also
distributes natural gas at retail in Iowa, Illinois, South Dakota and Nebraska.
As of December 31, 1999, MEC had 663,500 retail electric customers and 638,000
retail natural gas customers.

NORTHERN

-63-
<PAGE>

CALENERGY

The CalEnergy Platform is engaged in the development, ownership and operation of
environmentally responsible independent power production facilities worldwide
utilizing geothermal, natural gas, hydroelectric and other energy sources.
Through the Company's 50% owned subsidiary, CE Generation LLC ("CE Generation"),
the Company has interests in eight operating geothermal plants in Imperial
Valley, California and three operating natural gas fired cogeneration plants in
New York, Texas and Arizona. Plant capacity factors for Vulcan, Hoch (Del
Ranch), Elmore and Leathers (collectively the "Partnership Projects") are based
on capacity amounts of 34, 38, 38, and 38 net MW, respectively, and for Salton
Sea I, Salton Sea II, Salton Sea III and Salton Sea IV plants (collectively the
"Salton Sea Projects") are based on capacity amounts of 10, 20, 49.8 and 39.6
net MW, respectively (the Partnership Projects and the Salton Sea Projects are
collectively referred to as the "Imperial Valley Projects"). Plant capacity
factors for Saranac, Power Resources and Yuma (collectively the "Gas Plants")
are based on capacity amounts of 240, 200 and 50 net MW, respectively. The
Company accounts for CE Generation under the equity method.

The Company also indirectly owns the Upper Mahiao, Malitbog and Mahanagdong
Projects (collectively, the "Philippine Projects"), which are geothermal power
plants located on the island of Leyte in the Philippines. Plant capacity amounts
for the Upper Mahiao, Malitbog and Mahanagdong Projects are 119, 216 and 165 net
MW, respectively.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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. Investments other than
restricted cash are primarily commercial paper and money market securities.
Restricted cash is not considered a cash equivalent.

The current restricted cash and short term investment balance includes
commercial paper and money market securities, and is mainly composed of amounts
deposited in restricted accounts from which the Company will source its debt
service reserve requirements relating to the projects. These funds are
restricted by their respective project debt agreements to be used only for the
related project.

The long-term restricted cash and investment balances are mainly composed of
amounts deposited in restricted accounts from which the Company will fund the
various projects under construction.

The Company's restricted 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 that holds the investments.

The Company's nuclear decommissioning trust funds and other marketable
securities are classified as available for sale and are accounted for at fair
value.

-64-
<PAGE>

PROPERTY, PLANT, 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 that 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.

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 estimated useful lives of the
developed systems that range from 3 to 15 years.

An allowance for the estimated annual decommissioning costs of the Quad Cities
Nuclear Power Station (Quad Cities Station) equal to the level of funding is
included in depreciation expense. See Note 18 for additional information
regarding decommissioning costs.

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
$3.4 million, net of taxes of $2.2 million.

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.

EXCESS OF COST OVER FAIR VALUE OF NET ASSETS ACQUIRED

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 MidAmerican and Northern acquisitions, and a 32 year period for the
acquisition of KDG.

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, based on discounted cash flows or various models, whenever evidence
exists that the carrying value is not recoverable.

-65-
<PAGE>

REVENUE RECOGNITION

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

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.

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 does not intend 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 that are intended to be remitted.

NET INCOME PER COMMON SHARE

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 (in thousands, except per share amounts):

<TABLE>
<CAPTION>
1999 1998
------------------------------- -------------------------------
PER SHARE PER SHARE
INCOME SHARES AMOUNT INCOME SHARES AMOUNT
-------- ------ --------- -------- ------ ---------

<S> <C> <C> <C> <C> <C> <C>
Basic earnings per share before
extraordinary item and cumulative
effect of change in accounting principle $216,671 59,929 $3.62 $137,512 60,139 $2.29
Effect of dilutive securities:
Stock options .......................... -- 865 -- 634
Convertible preferred securities of
subsidiary trusts (1) .................. 19,383 11,154 21,883 13,327
-------- ------ -------- ------
Diluted earnings per share before
extraordinary item and cumulative
effect of change in accounting principle $236,054 71,948 $3.28 $159,395 74,100 $2.15
======== ====== ======== ====== ======
</TABLE>

-66-
<PAGE>

1997
-------------------------------
PER SHARE
INCOME SHARES AMOUNT
------- ------ ---------
Basic earnings per share before
extraordinary item and cumulative
effect of change in accounting principle. $51,823 67,268 $0.77
Effect of dilutive securities
Stock options............................ - 1,418
Convertible preferred securities of
subsidiary trusts (1).................... - -
------- ------
Diluted earnings per share before
extraordinary item and cumulative
effect of change in accounting principle. $51,823 68,686 $0.75
======= ======

(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. Resulting translation adjustments are reflected as accumulated
other comprehensive income in stockholders' equity. Revenues and expenses are
translated at average exchange rates for the year.

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 1998 and 1997 consolidated financial statements
and supporting note disclosures have been reclassified to conform to the fiscal
1999 presentation. Such reclassification did not impact previously reported net
income or retained earnings.

USE OF ESTIMATES

The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities

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<PAGE>

and disclosure of contingent assets and liabilities at the date of the
consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.

ACCOUNTING FOR LONG-TERM POWER PURCHASE CONTRACT

Under a long-term power purchase contract with Nebraska Public Power District
("NPPD"), expiring in 2004, MEC purchases one-half of the output of the
778-megawatt Cooper Nuclear Station. Other accrued liabilities include a
liability for MEC's fixed obligation to pay 50% of NPPD's Nuclear Facility
Revenue Bonds and other fixed liabilities.

Cooper capital improvement costs prior to 1997, including carrying costs, were
deferred in accordance with then applicable rate regulation, and are being
amortized and recovered in rates over either a five-year period or the term of
the power purchase contract. Beginning July 11, 1997, the Iowa portion of
capital improvement costs is recovered currently from customers and is expensed
as incurred. MEC began charging the remaining Cooper capital improvement costs
to expense for jurisdictions other than Iowa as incurred in January 1997.

The fuel cost portion of the power purchase contract is included in costs of
sales. All other costs MEC incurs in relation to its long-term power purchase
contract with NPPD are included in operating expense.

NEW ACCOUNTING PRONOUNCEMENT

3. BERKSHIRE TRANSACTION

The Company incurred approximately $6.7 million of non-recurring costs in 1999,
related to the Berkshire transaction, which were expensed.

4. ACQUISITIONS/DISPOSITIONS

MIDAMERICAN MERGER

On August 11, 1998, the Company entered into an Agreement and Plan of Merger
with MHC Inc., formerly MidAmerican Energy Holdings Company ("MHC"). The
MidAmerican Merger closed on March 12, 1999 and the

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<PAGE>

Company paid $27.15 in cash for each outstanding share of MHC common stock for a
total of approximately $2.42 billion in a merger, pursuant to which MHC 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. See discussion of Qualified Facilities Dispositions below.

The MidAmerican Merger has been accounted for as a purchase business combination
and as such the results of operations of the Company include the results of MHC
beginning March 12, 1999. The purchase price has been allocated to assets
acquired and liabilities assumed based on preliminary valuations. The final
purchase price allocation has not been completed, however, the Company does not
anticipate any material changes based on currently available information. The
Company recorded goodwill of approximately $1.5 billion, which is being
amortized using the straight-line method over a 40-year period.

Unaudited pro forma combined revenue, income before extraordinary item, net
income and basic earnings per share of the Company and MHC for the years ended
December 31, 1999 and 1998, as if the acquisition had occurred at the beginning
of each year after giving effect to certain pro forma adjustments related to the
acquisition and including the sales of the qualified facilities, the issuance of
senior secured notes and bonds and the redemptions of certain limited recourse
notes and senior discount notes, were $4.81 billion, $230.6 million, $181.3
million and $3.03, respectively, compared to $4.13 billion, $97.3 million, $97.3
million and $1.62, respectively.

QUALIFIED FACILITIES DISPOSITIONS

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

On February 26, 1999, the Company closed the sale of all of its indirect
ownership interests in the Coso Joint Ventures ("Coso") to Caithness Energy LLC
("Caithness") for $205 million in cash.

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 an aggregate
consideration of approximately $245 million in cash, $6.5 million in contingent
payments and $23.5 million in equity commitments. Due to the sale of 50% of its
interests in CE Generation, the Company has accounted for CE Generation as an
equity investment beginning March 3, 1999.

The sales of the qualified facilities resulted in a net non-recurring pre-tax
gain of $20.2 million and an after-tax gain of approximately $12.4 million or
$0.17 per diluted share.

MCLEOD

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<PAGE>

the sale were approximately $375 million, with a resulting pre-tax gain to the
Company of approximately $78.2 million, and an after-tax gain of approximately
$47.1 million or $0.65 per diluted share.

HOMESERVICES.COM

On October 18, 1999, the Company closed on its initial public offering of 3.25
million shares of common stock of HomeServices.Com ("HomeServices"), previously
a wholly-owned subsidiary of the Company, at $15 per share. HomeServices sold
2.19 million newly issued shares and the Company, the selling stockholder, sold
1.06 million of its HomeServices shares in the offering. The offering reduced
the Company's ownership in HomeServices to approximately 65%. The Company
recognized a pre-tax gain on the sale of its HomeServices stock of $7.9 million,
which is reported in interest and other income. The Company recognized a gain
for HomeServices' sale of newly issued stock of $9.1 million, net of deferred
tax of $0.8 million, which was recorded as a credit to additional paid in
capital.

KDG

On January 2, 1998, the Company completed the purchase of Kiewit Diversified
Group's ("KDG") ownership interest in various project partnerships and common
shares of the Company (the "KDG Acquisition") for a cash price of approximately
$1.16 billion, including transaction costs. KDG's ownership interest in the
Company comprised approximately 20.2 million 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.

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 geothermal steam fields and geothermal power facilities located in Central
Java in Indonesia with Perusahaan Petambangan Minyak Dan Gas Gumi Negara
("Pertamina"), the Indonesian national oil company, and executed separate
"take-or-pay" energy sales contracts ("ESCs") with both Pertamina and P.T. PLN
(Persero) ("PLN"), the Indonesian national electric utility. The Government of
Indonesia provided sovereign performance undertakings of the obligations under
the joint operating and "take-or-pay" contracts.

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<PAGE>

Following PLN's failure to pay such amounts, HCE and PPL demanded payment
pursuant to the sovereign performance undertakings issued by the Minister of
Finance ("MOF") on behalf of the Republic of Indonesia ("ROI") and, following
the ROI's failure to pay, brought an arbitration against the ROI for breach of
those undertakings. A final award was issued by an international arbitration
panel in the ROI arbitration on October 15, 1999 which found that the ROI
materially breached its performance undertakings and violated international law,
and the ROI was required to pay HCE and PPL an aggregate amount of approximately
$575 million.

The Company carried political risk insurance on its investment in HCE and PPL
through the Overseas Private Investment Corporation ("OPIC"), an agency of the
U.S. Government, as well as through private market insurers. Such insurance
covered expropriation of the Company's investment in HCE and PPL, as well as
material breaches by PLN of the ESCs and by the ROI of its performance
undertakings. On November 18, 1999, the Company received payment from OPIC and
the private market insurers totaling $290 million under its political risk
insurance policies, reflecting the return of its equity investment less policy
deductibles. Due primarily to the timing of the receipt of proceeds, the Company
recorded a pre-tax gain of approximately $40.3 million on the insurance proceeds
and an additional tax benefit of $17.7 million for an after-tax gain of $58.0
million, or $0.81 per diluted share.

5. PROPERTY, PLANT, CONTRACTS AND EQUIPMENT:

Property, plant, contracts and equipment comprise the following at December 31
(in thousands):

1999 1998
----------- -----------
<S> <C> <C>
Operating assets:
Utility generation and distribution system ......... $ 3,996,389 $ 1,305,806
Independent power plants ........................... 705,346 1,868,002
Wells and resource development ..................... 123,845 473,237
Power sales agreements ............................. -- 193,868
Other assets ....................................... 377,897 313,029
----------- -----------

Total operating assets ............................. 5,203,477 4,153,942

Less accumulated depreciation and amortization ..... (695,801) (769,526)
----------- -----------

Net operating assets ............................... 4,507,676 3,384,416

Mineral and gas reserves and exploration assets, net 476,416 375,208
Construction in progress:
Casecnan ...................................... 306,007 243,948
Zinc recovery project ......................... 92,794 24,183
Cordova ....................................... 79,982 --
Indonesia and other ........................... 454 208,284
----------- -----------

TOTAL .............................................. $ 5,463,329 $ 4,236,039
=========== ===========
</TABLE>

MINERALS EXTRACTION

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<PAGE>

CASECNAN

On November 20, 1999, pursuant to an amendment of the Casecnan Construction
Contract which was approved by the independent engineer under the Bond
Indenture, the Guaranteed Substantial Completion Date for the Casecnan Project
was extended to March 31, 2001. Accordingly, the Casecnan Project is now
expected to become operational by the second quarter of 2001.

CORDOVA

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<PAGE>

6. PARENT COMPANY DEBT

Parent company debt comprises the following at December 31 (in thousands):

1999 1998
---------- ----------
Senior Discount Notes ............... $ -- $ 369,501
9.5% Senior Notes ................... 32 224,265
7.63% Senior Notes .................. 350,000 350,000
Limited Recourse Senior Secured Notes 4,225 200,000
$1.4 Billion Senior Notes ........... 1,400,000 1,400,000
$100 Million Senior Notes ........... 102,061 102,225
---------- ----------
$1,856,318 $2,645,991
========== ==========

SENIOR DISCOUNT NOTES

In March 1994, the Company issued $400 million of 10.25% Senior Discount Notes
which accreted to an aggregate principal amount of $529.6 million 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 $160.1 million 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 extraordinary losses, net of tax, of
$14.0 million and $7.1 million in 1999 and 1998 respectively.

9.5% SENIOR NOTES

On September 20, 1996, the Company issued $225 million of 9.5% Senior Notes (the
"9.5% Senior Notes") due in 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. During 1999, the
Company repurchased and retired substantially all of the notes at an average
price of 110.055% plus accrued interest. Due to the early extinguishments of the
9.5% Senior Notes, the Company recorded an extraordinary loss in 1999 of $17.9
million, net of tax. The 9.5% Senior Notes are unsecured senior obligations of
the Company.

7.63% SENIOR NOTES

On October 28, 1997, the Company issued $350 million of 7.63% Senior Notes (the
"7.63% Senior Notes") due in 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 million of 9 7/8% Limited Recourse
Senior Secured Notes due in 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 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, 1999.

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<PAGE>

paid on March 3, 1999 at a redemption price of 110.025% plus accrued interest.
Due to early extinguishments of the Limited Recourse Notes, the Company recorded
an extraordinary loss of $17.5 million, net of tax. 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. The Company expects to redeem the remaining Limited Recourse
Notes on or about June 30, 2000.

$1.4 BILLION SENIOR NOTES

On September 22, 1998, the Company issued $215 million of 6.96% Senior Notes due
in 2003, $260 million of 7.23% Senior Notes due in 2005, $450 million of 7.52%
Senior Notes due in 2008, and $475 million of 8.48% Senior Bonds due in 2028
(collectively, the "$1.4 Billion Senior Notes"). Interest on the $1.4 Billion
Senior Notes is 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 million at a premium of
approximately 102.243% of 7.52% Senior Notes (the "$100 Million Senior Notes")
due in 2008. Interest on the $100 Million Senior Notes is 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

The Company has available a $400 million revolving credit facility expiring in
November 2000. The facility is unsecured and is available to fund working
capital requirements and finance future business expansion opportunities. There
was no outstanding balance under this revolving credit facility as of December
31, 1999.

7. SUBSIDIARY AND PROJECT DEBT

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

1999 1998
---------- ----------
<S> <C> <C>
MidAmerican Funding, LLC Senior Notes and Bonds .............. $ 702,089 $ --
MEC Mortgage Bonds ........................................... 450,570 --
MEC Pollution Control Bonds .................................. 157,129 --
MEC Notes .................................................... 262,240 --
MEC Commercial Paper ......................................... 204,000 --
MidAmerican Capital Notes .................................... 70,098 --
HomeServices Senior Notes and Revolving Debt ................. 48,817 --
Salton Sea Notes and Bonds ................................... 140,520 626,816
Northern Eurobonds ........................................... 324,850 426,785
CE Electric UK Funding Company Senior Notes and Sterling Bonds 670,327 684,986
Casecnan Notes and Bonds ..................................... 363,085 371,500
Philippine Term Loans ........................................ 449,739 517,998
Northern Short Term Treasury Loan ............................ 174,593 72,740
Cordova Funding Senior Secured Bonds ......................... 124,824 --
CE Gas Loan .................................................. 113,267 41,355
CE Indonesia Funding Corp. Construction Loans, Power
Resources and Coso Funding Corp. Project Debt and Other .... 1,280 351,630
---------- ----------
$4,257,428 $3,093,810
========== ==========
</TABLE>

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<PAGE>

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; 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 Northern, MHC, HomeServices or the Imperial
Valley, Saranac, Power Resources, Mahanagdong, Malitbog, Upper Mahiao, Casecnan,
and Cordova projects or (2) owning interests in the subsidiaries that own
interests in the foregoing subsidiaries or projects.

MIDAMERICAN FUNDING, LLC SENIOR NOTES AND BONDS

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

MEC MORTGAGE BONDS, POLLUTION CONTROL BONDS AND NOTES

The components of MEC's Mortgage Bonds, Pollution Control Bonds and Notes at
December 31, 1999 are as follows (in thousands):

Mortgage bonds:
6% Series, due 2000......................................... $ 35,000
6.75% Series, due 2000...................................... 75,000
7.125% Series, due 2003..................................... 100,000
7.70% Series, due 2004...................................... 55,630
7% Series, due 2005......................................... 90,500
7.375% Series, due 2008..................................... 75,000
7.45% Series, due 2023...................................... 6,940
6.95% Series, due 2025...................................... 12,500
--------
$450,570
========

Pollution control revenue obligations:
5.75% Series, due periodically through 2003................. $ 7,704
5.95% Series, due 2023 (secured by general mortgage bonds).. 29,030
Variable rate series -
Due 2016 and 2017, 3.95% ................................ 37,600
Due 2023 (secured by general mortgage bond, 3.95%)....... 28,295
Due 2023, 3.95%.......................................... 6,850
Due 2024, 3.95%.......................................... 34,900
Due 2025, 3.95%.......................................... 12,750
--------
$157,129
========

Notes:
8.75% Series, due 2002...................................... $ 240
6.5% Series, due 2001....................................... 100,000
6.375% Series, due 2006..................................... 160,000
6.7% Series, due 2003....................................... 1,000
6.1% Series, due 2007....................................... 1,000
--------
$262,240
========

MEC COMMERCIAL PAPER

MEC has authority from the Federal Energy Regulatory Commission ("FERC") to
issue short-term debt in the form of commercial paper and bank notes aggregating
$400 million for interim financing of working capital needs. As of December 31,
1999, MEC had a $250 million revolving credit facility and lines of credit
totaling $95 million

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<PAGE>

and MHC had lines of credit totaling $24 million. MEC's commercial paper
borrowings are supported by the revolving credit facility and the lines of
credit. As of December 31, 1999, commercial paper and bank notes totaled $204
million for MEC with a weighted average interest rate of 6.3%.

MIDAMERICAN CAPITAL NOTES

MidAmerican Capital Company, a wholly owned subsidiary of the Company, has debt
of $70 million of 8.52% Senior Notes. These notes are due in annual increments
of $23.3 million beginning in 2000 with final payment in 2002.

HOMESERVICES SENIOR NOTES AND REVOLVING DEBT

HomeServices debt includes $35 million of 7.12% Senior Notes due in annual
increments of $5 million beginning in 2004. HomeServices also obtained a $75
million senior secured revolving credit facility of which HomeServices had drawn
down $11 million as of December 31, 1999. This credit agreement has a variable
interest rate at either the prime lending rate or LIBOR plus a fixed spread of
1.25% to 2.50% that varies based on HomeServices' cash flow leverage ratio, as
defined in the agreement. As of December 31, 1999, the blended average interest
rate on the senior secured revolving credit facility borrowings was 8.08%.

SALTON SEA NOTES AND BONDS

As the Company's interest in Salton Sea Funding Corporation was transferred to
CE Generation, the balance of Salton Sea Notes and Bonds as of December 31, 1998
of $626.8 million is included in the Company's equity investment in CE
Generation as of December 31, 1999. However, the Company retained CalEnergy
Minerals LLC, which is one of the guarantors of this debt. As a result of a note
allocation agreement, CalEnergy Minerals LLC is primarily responsible for
$140.52 million of the 7.475% Senior Secured Series F Bonds due November 30,
2018. The Company has guaranteed a specified portion of the scheduled debt
service on the Series F Bonds equal to the current principal amount of $140.52
million and associated interest.

NORTHERN EUROBONDS

The balance at December 31, 1999 and 1998 consists of the following (in
thousands):

1999 1998
-------- --------
12.661% Debenture due 1999 ................... $ -- $ 94,393
8.625% Bearer bonds due 2005 ................. 162,512 166,286
8.875% Bearer bonds due 2020 ................. 162,338 166,106
-------- --------
$324,850 $426,785
======== ========

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 the Senior Notes and
Sterling Bonds. The balances at December 31 are comprised of the following (in
thousands):

1999 1998
-------- --------
6.853% Senior Notes due 2004 ................. $121,754 $124,376
6.995% Senior Notes due 2007 ................. 230,662 235,694
7.25% Sterling Bonds due 2022 ................ 317,911 324,916
-------- --------
$670,327 $684,986
======== ========

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<PAGE>

The CE Electric UK Funding Company Senior Notes 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 million 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 million 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 $12.1 million based on quotes from the counterparty
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 these swap agreements to maturity.

CASECNAN NOTES AND BONDS

On November 27, 1995, CE Casecnan issued $371.5 million of notes and bonds to
finance the construction of the Casecnan Project. These consist of $75 million
Senior Secured Floating Rate Notes (FRNs) due in 2002; $125 million Senior
Secured Series A Notes (Series A Notes) with interest at 11.45% due in 2005; and
$171.5 million Senior Secured Series B Bonds (Series B Bonds) with interest at
11.95% due in 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. During 1999, the Company purchased
$8.4 million of the FRNs.

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.

PHILIPPINE TERM LOANS

On April 8, 1998, the Company converted the construction project financing for
its Malitbog geothermal power project to term loans. OPIC is providing term loan
financing of $46.8 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 $84.4 million at a variable interest rate based on LIBOR
(8.37% at December 31, 1999). The loans have scheduled repayments through June
2005.

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 $121.3 million
at a fixed interest rate of 5.95%. United Coconut Planters Bank of the
Philippines is providing term loan financing of $8.3 million at a variable
interest rate based on LIBOR (9.10% at December 31, 1999). The loans have
scheduled repayments through June 2006.

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 $154.6 million at a fixed rate of 6.92%. OPIC is
providing term loan financing of $34.3 million 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, 1999 and
1998 of $174.6 million and $72.7 million, respectively. The amounts have varying
maturities generally less than one month and carry variable interest rates based
on LIBOR and ranging from 5.58% to 6.19% at December 31, 1999.

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<PAGE>

CORDOVA FUNDING SENIOR SECURED BONDS

On September 10, 1999 Cordova Funding Corporation ("Cordova Funding"), a wholly
owned subsidiary of the Company, closed the $225 million aggregate principal
amount financing for the construction of the Cordova Project. As part of the
financing, approximately $93.5 million of 8.64% Series A-1 Senior Secured Bonds
due in 2019 were issued. An additional $31.3 million of 8.79% Series A-2 Senior
Secured Bonds due in 2019 were issued on December 15, 1999. Additional Series A
Senior Secured Bonds will be issued as required to fund construction. Cordova
Funding will loan the proceeds to Cordova Energy as required.

CE GAS LOAN

CE Gas, a wholly owned subsidiary of the Company, had borrowed $113.3 million
and $41.4 million on a 70 million pounds sterling revolving facility at December
31, 1999 and 1998, respectively, to fund the purchases of certain UK gas assets
in the North Sea. The amount carries a variable interest rate based on LIBOR
(7.055% at December 31, 1999). The revolving facility was completely utilized at
December 31, 1999.

ANNUAL REPAYMENTS OF SUBSIDIARY AND PROJECT DEBT

The annual repayments of the subsidiary and project debt for the years beginning
January 1, 2000 and thereafter are as follows (in thousands):

MIDAMERICAN MIDAMERICAN
FUNDING, MIDAMERICAN ENERGY NOTES,
LLC MIDAMERICAN ENERGY COMMERCIAL HOMESERVICES
SENIOR ENERGY POLLUTION PAPER & SENIOR NOTES SALTON
NOTES AND MORTGAGE CONTROL MIDAMERICAN AND REVOLVING SEA NORTHERN
BONDS BONDS BONDS CAPITAL NOTES DEBT BONDS EUROBONDS
--------- ----------- ----------- ------------- ------------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
2000 $ - $110,000 $ 504 $227,578 $ 707 $ - $ -
2001 200,000 - 1,440 123,333 730 632 -
2002 - - 1,440 23,574 11,694 2,108 -
2003 - 100,000 5,320 - 482 1,405 -
2004 - 55,630 - - 5,084 1,757 -
Thereafter 502,089 184,940 148,425 162,203 30,120 134,618 324,850
-------- -------- -------- --------- ------- -------- --------
$702,089 $450,570 $157,129 $536,688 $48,817 $140,520 $324,850
======== ======== ======== ======== ======= ======== ========

</TABLE>

CE ELECTRIC UK
FUNDING COMPANY NORTHERN CORDOVA
SENIOR SHORT TERM FUNDING
NOTES AND TREASURY CASECNAN PHILIPPINE SENIOR
STERLING CE LOAN NOTES AND TERM SECURED
BONDS GAS LOAN AND OTHER BONDS LOANS BONDS TOTAL
-------------- --------- ----------- ---------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
2000 $ - $ 15,508 $ 175,523 $ 16,646 $ 68,259 $ - $ 614,725
2001 - 19,340 - 26,301 68,259 - 440,035
2002 - 17,553 - 32,213 68,259 699 157,540
2003 - 21,640 - 41,468 72,148 4,993 247,456
2004 121,754 21,045 - 49,360 67,148 4,494 326,272
Thereafter 548,573 18,181 - 197,097 105,666 114,638 2,471,400
-------- -------- ---------- --------- --------- -------- ----------
$670,327 $113,267 $ 175,523 $ 363,085 $ 449,739 $124,824 $4,257,428
======== ======== ========== ========= ========= ======== ==========
</TABLE>

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<PAGE>

8. INCOME TAXES

Provision for income taxes was comprised of the following at December 31 (in
thousands):

1999 1998 1997
-------- ------- --------
Current:
State ............ $ 7,337 $ 5,677 $ 5,084
Federal .......... 128,839 33,160 33,114
Foreign .......... 13,889 20,096 5,262
-------- ------- --------
150,065 58,933 43,460
-------- ------- --------
Deferred:
State ............ 1,791 161 (264)
Federal .......... (75,510) 14,973 14,579
Foreign .......... 17,129 19,198 41,269
-------- ------- --------
(56,590) 34,332 55,584
-------- ------- --------
Total ............ $ 93,475 $93,265 $ 99,044
======== ======= ========

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

1999 1998 1997
----- ----- -----
Federal statutory rate ......................... 35.00% 35.00% 35.00%
Percentage depletion in excess of cost depletion (.38) (3.52) (3.77)
Investment and energy tax credits .............. (1.78) (.93) (.64)
State taxes, net of federal tax effect ......... 1.66 1.71 1.59
Goodwill amortization .......................... 5.46 2.51 2.06
Dividends on preferred
securities of subsidiary trusts* ........... (3.75) (4.63) (4.12)
Tax effect of foreign income ................... .36 1.86 2.64
Non-recurring items on Indonesia ............... (10.99) -- 15.47
Other .......................................... .60 2.28 2.08
----- ----- -----
Effective tax rate ............................. 26.18% 34.28% 50.31%
===== ===== =====

* Dividends on convertible and non-convertible preferred securities of
subsidiary trusts are included in minority interest.

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

1999 1998
----------- ---------
Depreciation and amortization, net ............... $ 983,038 $ 769,376
Income taxes recoverable through future rates .... 187,379 --
Demand side management ........................... 14,805 --
Reacquired debt .................................. 12,476 --
Pensions/profit sharing .......................... -- 22,305
Unremitted foreign earnings ...................... -- 25,393
----------- ---------
1,197,698 817,074
----------- ---------

Nuclear reserve and decommissioning .............. (20,280) --
Deferred income .................................. (19,502) (9,458)
Deferred contract costs .......................... (215,388) (182,745)
General business tax credits ..................... -- (21,300)
Alternative minimum tax credits .................. -- (44,452)
Accruals not currently deductible for tax purposes (32,211) (11,591)
Other ............................................ (7,449) (4,137)
----------- ---------
(294,830) (273,683)
----------- ---------
Net deferred income taxes ........................ $ 902,868 $ 543,391
=========== =========

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<PAGE>

9. 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 (in thousands):

CONVERSION
ISSUER ISSUE DATE RATE AMOUNT 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 $103.9 million, $180 million and $270
million, 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. Prior to the Berkshire
transaction, each Trust Security with a par value of $50 was convertible at the
option of the holder at any time into shares of the Company's common stock based
on the conversion rate. As a result of the Berkshire transaction, in lieu of
shares of the Company's common stock, holders of Trust Securities will receive
$35.05 for each share of common stock it would have been entitled to receive on
conversion.

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.

On May 18, 1999, CalEnergy Capital Trust I effected the conversion of $103.9
million of the convertible preferred securities into approximately 3.5 million
shares of common stock of the Company. The Securities were converted at a rate
equivalent to a conversion price of $29.89 per share of Company common stock.

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

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

In December 1996, MidAmerican Energy Financing I, a wholly owned statutory
business trust of MEC, issued 4,000,000 shares of 7.98% Series MEC-obligated
mandatorily redeemable preferred securities . The sole assets of MidAmerican
Energy Financing are $103.1 million of MEC 7.98% Series A Debentures due 2045
(the "Debentures"). There is a full and unconditional guarantee by MEC of
MidAmerican Energy Financing's obligations under the preferred securities. MEC
has the right to defer payments of interest on the Debentures by extending the
interest payment period for up to 20 consecutive quarters. If interest payments
on the Debentures are deferred, distributions on the preferred securities will
also be deferred. During any deferral, distributions will

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<PAGE>

continue to accrue with interest thereon, and MEC may not declare or pay any
dividend or other distribution on, or redeem or purchase, any of its capital
stock.

The Debentures may be redeemed by MEC on or after December 18, 2001, or at an
earlier time if there is more than an insubstantial risk that interest paid on
the Debentures will not be deductible for federal income tax purposes. If the
Debentures, or a portion thereof, are redeemed, MidAmerican Energy Financing
must redeem a like amount of the preferred securities. If a termination of
MidAmerican Energy Financing occurs, MidAmerican Energy Financing will
distribute to the holders of the preferred securities a like amount of the
Debentures unless such a distribution is determined not to be practicable. If
such determination is made, the holders of the preferred securities will be
entitled to receive, out of the assets of MidAmerican Energy Financing after
satisfaction of its liabilities, a liquidation amount of $25 for each preferred
security held plus accrued and unpaid distributions.

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 are automatically attached to, and trade
with, each share of common stock.

In 1999, the Board of Directors renewed the Company's shareholder rights plan.
The expiration date of the rights plan was extended to September 14, 2009. The
amended plan reflects prevailing shareholder rights plan terms. The share
ownership level which triggers the exercise of the rights and the flip-in and
flip-over features of the rights plan has been reduced to 15% and the exercise
price of the rights has been increased to $140 per right. The Berkshire
transaction was approved by the Board of Directors and did not trigger the
dividend of a preferred share purchase right.

12. STOCK OPTIONS AND RESTRICTED STOCK

The Company has various stock option plans under which shares were reserved for
grant as incentive or non-qualified stock options, as determined by the Board of
Directors. The plans 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. As a result of the Berkshire transaction, all
options, except for David Sokol's and Greg Abel's, were cashed out at $35.05 per
share.

The Company granted 500 shares of restricted common stock with an aggregate
market value of $9.5 million in exchange for the relinquishment of 500 stock
options that 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, $5.5 million of unearned compensation was charged to operating
expense in 1997.

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<PAGE>

TRANSACTIONS IN STOCK OPTIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>

SHARES OPTIONS OUTSTANDING
AVAILABLE -------------------------------------------
FOR GRANT
UNDER 1996 OPTION PRICE WEIGHTED AVG.
OPTION PLAN SHARES PER SHARE OPTION PRICE TOTAL
----------- ------ ---------------- ------------- --------
<S> <C> <C> <C> <C> <C> <C>
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
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 granted ............... (1,106) 1,106 15.10 - 32.56 28.88 31,937
Options terminated ............ 386 (386) 9.71 - 34.69 27.72 (10,689)
Options exercised ............. -- (171) 9.71 - 26.29 17.68 (3,018)
____________________________________________________________________
Balance December 31, 1999 .......... 355 6,259 $9.71 - $34.69 $ 24.95 $156,183
____________________________________________________________________

Options exercisable at:
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
December 31, 1999 3,776 $9.71 - $34.56 $ 22.17 $ 83,708
</TABLE>

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, 1999 (in thousands, except per share amounts):

WEIGHTED
WEIGHTED AVERAGE WEIGHTED
RANGE OF AVERAGE REMAINING AVERAGE
EXERCISED NUMBER EXERCISE CONTRACTUAL NUMBER EXERCISE
PRICES OUTSTANDING PRICE LIFE EXERCISABLE PRICE
- --------------- ----------- -------- ----------- ----------- --------
$ 9.71 $18.99 1,531 $16.23 4 years 1,529 $16.23
19.00 24.99 1,298 21.30 6 years 906 21.30
25.00 28.99 1,224 28.41 8 years 615 28.42
29.00 34.69 2,206 31.81 9 years 726 31.73
----- -----
6,259 24.96 7 years 3,776 22.17
===== =====

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 $5.5
million or $0.09 per

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<PAGE>

share in 1999, $4.8 million, or $0.08 per share for 1998 and $3.6 million, or
$0.05 per share for 1997. The fair value for stock options was estimated using
the Black-Scholes option pricing model with the weighted average fair value of
options granted during 1999, 1998 and 1997 of $11.17, $7.71 and $9.55 per
option, respectively using the following assumptions:

1999 1998 1997
---- ---- ----
Risk-fee interest rate 5.10% 5.10% 5.50%
Expected volatility 31.50% 34.50% 25.00%
Expected life 4.8 years 3.4 years 3.7 years
Expected dividends 0% 0% 0%

13. EQUITY OFFERING

On October 17, 1997, the Company completed the public offering of 17.1 million
shares of its common stock at $37 7/8 per share (the "Public Offering"). In
addition, 2 million shares of common stock were purchased from the Company in a
direct sale by a trust affiliated with Walter Scott (the "Direct Sale"),
contemporaneously with the closing of the Public Offering. Proceeds from the
Public Offering and the Direct Sale were approximately $699.9 million.

14. UK WINDFALL TAX

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 1997 budget. This amounted to $135.9 million,
net of minority interest of $58.2 million, which was recorded as an
extraordinary item. The first installment was paid December 1, 1997 and the
remainder was paid in 1998.

15. 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 term loans and CE Indonesia Funding
Corp. construction loans as there are no quoted market prices available.

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

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<PAGE>

1999 1998
---- ----
ESTIMATED ESTIMATED
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
---------- ----------- ---------- ---------
(IN THOUSANDS)

<S> <C> <C> <C> <C>
Senior Discount Notes $ -- $ -- $ 369,501 $ 388,438
9.5% Senior Notes 32 34 224,265 243,328
7.63% Senior Notes 350,000 346,220 350,000 372,365
Limited Recourse Senior Secured Notes 4,225 4,449 200,000 217,900
$1.4 Billion Senior Notes 1,400,000 1,396,360 1,400,000 1,495,742
$100 Million Senior Notes 102,061 97,920 102,225 111,973
MidAmerican Funding, LLC Senior Notes and Bonds 702,089 638,101 -- --
MEC Mortgage Bonds 450,570 445,502 -- --
MEC Pollution Control Bonds 157,129 157,868 -- --
MEC Notes 262,240 249,084 -- --
MEC Commercial Paper 204,000 204,000 -- --
MidAmerican Capital Notes 70,098 71,526 -- --
HomeServices Senior Notes and Revolving Debt 48,817 44,862 -- --
Saton Sea Bonds 140,520 128,815 626,816 646,397
Northern Eurobonds 324,850 379,987 426,785 516,080
CE Electric UK Funding Company Senior Notes
and Sterling Notes 670,327 671,779 684,986 772,900
Casecnan Notes and Bonds 363,085 353,789 371,500 302,248
Northern Short Term Treasury Loan 174,593 174,593 72,740 72,740
Cordova Funding Senior Secured Bonds 124,824 120,399 -- --
CE Gas Loan 113,267 113,267 41,355 41,355
Power Resources Project Debt, Coso
Funding Corp. Project Loans and Other 1,280 1,280 159,152 162,575
Convertible Preferred Securities of Subsidiary Trusts 450,000 353,925 553,930 562,012
Preferred Securities of Subsidiary Trusts 101,598 87,240 -- --
Preferred Securities of Subsidiaries 146,606 135,216 66,033 66,033
</TABLE>

The amortized cost, gross unrealized gain and losses and estimated fair value of
investments in debt and equity securities at December 31 are as follows (in
thousands):

1999
--------------------------------------------
Amortized Unrealized Unrealized Fair
Cost Gains Losses Value
--------- ---------- ---------- --------
Available-for-sale:
Equity securities ......... $122,327 $ 37,941 $ (13,530) $146,738
Municipal bonds ........... 30,913 868 (355) 31,426
U. S. Government securities 14,159 78 (123) 14,114
Corporate securities ...... 26,935 5 (1,511) 25,429
Cash equivalents .......... 8,591 -- -- 8,591
-------- -------- --------- --------
$202,925 $ 38,892 $ (15,519) $226,298
======== ======== ========= ========

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<PAGE>

16. REGULATORY MATTERS

NORTHERN

Northern is subject to price cap regulation and the Office of Gas and
Electricity Markets ("Ofgem") enforces the price control formulas for the supply
and distribution businesses.

The current distribution price control period expires on March 31, 2000. The
changes to the formula took effect from April 1, 1995 and April 1, 1996
resulting 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
regulated distribution income per unit is increased or decreased each year by
RPI-Xd where RPI reflects the average of the twelve months' 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 December 1999 Northern accepted Ofgem's proposals for the next distribution
price control period which will bring about a further one-time reduction of
around 24% in regulated distribution income with effect from April 1, 2000 with
continuing Xd of 3% in each subsequent year.

As a result of the distribution price reviews, Northern implemented a review of
staffing requirements primarily in its distribution business. Following
discussions with the trade unions, Northern put in place a workforce reduction
program. The Company recorded a non-recurring pre-tax loss of approximately
$47.7 million and an after-tax loss of approximately $29.2 million or $0.41 per
diluted share in 1999 due to costs associated with the reduction of Northern's
workforce.

Northern's current supply price control applies only to domestic and some
smaller non-domestic customers in the North East of England and is due to expire
on March 31, 2000. The current formula took effect on April 1, 1998 and required
Northern to reduce prices to those customers from the level prevailing at August
1, 1997 by about 4.2% (minus inflation) from April 1, 1998 and by a further 3%
(minus inflation) from April 1, 1999.

In December 1999, Northern accepted Ofgem's proposals for the next supply price
control period to be effective from April 1, 2000 until March 31, 2002. The new
control relates to domestic customers only and will lead to a further price
reduction for those customers of 10.8% in real terms with effect from April 1,
2000.

The market for electricity supplied to customers with demands of over 1 MW was
opened to competition in 1990. In 1994, this limit was reduced to 0.1 MW. During
1998, liberalization of the entire market commenced in stages and was completed
during 1999.

MEC

As a result of a negotiated settlement in Illinois, MEC reduced its Illinois
electric service rates by annual amounts of $13.1 million and $2.4 million,
effective November 3, 1996, and June 1, 1997, respectively. MEC implemented an
additional $0.9 million annual rate reduction for its Illinois residential
customers, effective August 1, 1998, in connection with Illinois' electric
utility restructuring law.

On June 27, 1997, the Iowa Utilities Board approved a March 1997 settlement
agreement between MEC, the Iowa Office of Consumer Advocate and other parties.
Four major components of the settlement and their status are as follows:

1) On an annualized basis, prices for residential customers were reduced $8.5
million, $10.0 million and $5.0 million effective November 1, 1996, July 11,
1997, and June 1, 1998, respectively, for a total annual decrease of $23.5
million.

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<PAGE>

2) Prices for industrial customers were reduced by $6 million annually and
prices for commercial customers were reduced by $4 million annually. MEC was
given permission to implement these reductions through a retail access pilot
project, negotiated individual contracts and tariffed rate reductions. On
January 1, 1999, MEC reduced base rates for selected non-contract commercial
customers by approximately $1.5 million annually, subject to Iowa Utilities
Board approval. The remainder of the commercial and industrial price reductions
were achieved through negotiated contracts and a retail access pilot project.

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. The
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 MEC incurs to fulfill these
contracts will vary. On an aggregate basis the annual revenues under contract
are approximately $180 million.

3) The Iowa energy adjustment clause was eliminated. Prior to July 11, 1997, MEC
collected fuel costs from Iowa customers on a current basis through the 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. If the actual per-unit fuel cost varies from
that factor, pre-tax earnings are affected. The fuel cost factor was to be
reviewed in February 1999 and adjusted prospectively if the actual 1998 fuel
cost per unit varied by more than 15% above or below the factor included in base
rates. Based on 1998 actual fuel costs, MEC reduced the fuel cost recovery
factor in 1999 base rates effective March 1, 1999. The estimated annual
reduction in revenues associated with this adjustment is $1.1 million.

4) If MEC's annual Iowa electric jurisdictional return on common equity exceeds
12%, an equal sharing between customers and shareholders of earnings above the
12% level begins; if it exceeds 14%, two-thirds of MEC's share of those earnings
will be used for accelerated recovery of regulatory assets. The agreement
precludes MEC 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%.

Under a restructuring law enacted in 1997, a similar sharing mechanism is in
place for Illinois operations. Two-year average returns on common equity greater
than a two-year average benchmark will trigger an equal sharing of earnings on
the excess. The benchmark is a calculation of average 30-year Treasury Bond
rates plus 5.5% for 1998 and 1999 and 8.5% for 2000 through 2004. The initial
calculation, due March 31, 2000, will be based on 1998 and 1999 results.

17. PENSION COMMITMENTS

UNITED KINGDOM OPERATIONS

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, 1999, 1998 and 1997 assumed interest
rates of 6.0%, 5.5% and 6.75% respectively, an expected return on plan assets of
6.5%, 6.0% and 7.25%, respectively, and annual compensation increases of 3.0%,
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.

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<PAGE>

The following table details the funded status and the amount recognized in the
consolidated balance sheets for Northern's plan as of December 31, 1999 and 1998
(in thousands):

1999 1998
----------- ------------

Change in benefit obligation:
Benefit obligation at beginning of year .......... $ 926,000 $ 888,500
Service cost ..................................... 10,200 12,600
Interest cost .................................... 48,500 58,800
Participant contributions ........................ 5,700 5,800
Benefits paid .................................... (53,700) (46,700)
FAS 88 curtailment ............................... 38,300 --
Experience loss (gain) and change of assumptions . (34,400) 7,000
----------- -----------
Benefit obligation at end of the year ............ 940,600 926,000
----------- -----------

Change in plan assets:
Fair value of plan assets at beginning of the year 1,143,100 1,012,600
Actual return on plan assets ..................... 181,600 154,200
Contributions .................................... 12,600 23,000
Benefits paid .................................... (53,700) (46,700)
----------- -----------
Fair value of plan assets at end of the year ..... 1,283,600 1,143,100
----------- -----------

Funded status .................................... 343,000 217,100
Unrecognized net gain ............................ 300,100 140,200
----------- -----------
Prepaid benefit cost ............................. $ 42,900 $ 76,900
=========== ===========

As a result of the distribution price reviews, Northern implemented a review of
staffing requirements primarily in its distribution business. Following
discussions with the trade unions, Northern put in place a workforce reduction
program. The Company recorded a non-recurring pre-tax loss of approximately
$47.7 million which included a pension curtailment of $38.3 million.

Net periodic pension cost (benefit) for Northern's plan for 1999, 1998 and 1997
included the following components (in thousands):

1999 1998 1997
------- ------- --------

<S> <C> <C> <C>
Service cost - benefits earned during the period. $10,200 $12,600 $ 12,600
Interest cost on projected benefit obligation.... 48,500 58,800 62,400
Actual return on plan assets..................... (59,500) (68,000) (71,400)
------- ------- --------
Net periodic pension cost (benefit).............. $ (800) $ 3,400 $ 3,600
======= ======= ========
</TABLE>

DOMESTIC OPERATIONS

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

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

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<PAGE>

discretion. MEC expenses postretirement benefit costs on an accrual basis and
includes provisions for such costs in rates.

In 1999, the noncontributory cash balance defined benefit pension plans, the
noncontributory, nonqualified supplemental executive retirement plan, and the
postretirement plans were amended to include participants from the Company.
Prior to the amendment, these plans included only employees and participants of
MEC, MidAmerican Capital and Midwest Capital. This inclusion increased the
benefit obligation by $14.8 million for the pension and nonqualified
supplemental retirement plans and $2.8 million for the postretirement plans and
is reflected in the Benefit Obligation of MEC as of December 31, 1999.

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

Net periodic pension, supplemental retirement and postretirement benefit costs
included the following components for the Company for the period from March 12,
1999 through December 31, 1999 (in thousands):

Pension Cost Postretirement Cost
------------ -------------------

Service cost.......................... $ 9,854 $ 2,478
Interest cost......................... 25,505 6,423
Expected return on plan assets........ (37,392) (3,540)
Curtailment loss...................... 4,270 -
-------- -------
Net periodic pension cost (benefit). $ 2,237 $ 5,361
======== =======

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

Although the supplemental executive retirement plans had no plan assets as of
December 31, 1999, MEC has Rabbi trusts which hold corporate-owned life
insurance to provide funding for the future cash requirements. Because these
plans are nonqualified, the fair value of these assets is not included in the
following table. The fair value of the life insurance policies was $64.8 million
at December 31, 1999.

During 1999 certain participants in the supplemental executive retirement plan
left MEC reducing the future service of active employees by 28%. As a result, a
curtailment loss of $4.3 million was recognized by the Company in the period
from March 12, 1999 through December 31, 1999. Additionally, termination
benefits provided to the participants, totaling $3.5 million, were expensed by
MEC during the year ended December 31, 1999.

The projected benefit obligation and accumulated benefit obligation for the
supplemental executive retirement plans were $68.8 million and $65.5 million,
respectively, as of December 31, 1999.

The following table presents a reconciliation of the beginning and ending
balances of the benefit obligation, fair value of plan assets and the funded
status of the Company plans to the net amounts recognized in the consolidated
balance sheet as of December 31, 1999 (dollars in thousands):

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<PAGE>

Pension Postretirement
Benefits Benefits
--------- --------------
Reconciliation of benefit obligation:
Benefit obligation at beginning of year ........ $ 456,475 $ 120,188
Service cost ................................... 12,192 3,066
Interest cost .................................. 31,556 7,947
Participant contributions ...................... 107 1,838
Plan amendments ................................ 14,823 2,775
Actuarial gain ................................. (41,567) (18,248)
Curtailment .................................... (705) --
Termination benefits ........................... 3,471 --
Benefits paid .................................. (29,182) (9,822)
--------- ---------
Benefit obligation at end of year .......... 447,170 107,744
--------- ---------

Reconciliation of the fair value of plan assets:

Fair value of plan assets at beginning of year . 524,508 63,093
Employer contributions ......................... 4,201 12,405
Participant contributions ...................... 107 1,838
Actual return on plan assets ................... 105,425 5,108
Benefits paid .................................. (29,182) (9,822)
--------- ---------
Fair value of plan assets at end of year ... 605,059 72,622
--------- ---------

Funded status .................................. 157,889 (35,122)
Unrecognized net gain .......................... (101,434) (18,943)
Unrecognized prior service cost ................ 9,540 2,776
--------- ---------
Net amount recognized in the consolidated
balance sheet ............................ $ 65,995 $ (51,289)
========= =========

Pension Postretirement
Benefits Benefits
--------- --------------
Amounts recognized in the consolidated balance
sheet consist of:
Prepaid benefit cost ......................... $ 108,907 $ 1,042
Accrued benefit liability .................... (65,533) (52,331)
Intangible asset ............................. 22,621 --
--------- ---------
Net amount recognized .................... $ 65,995 $ (51,289)
========= =========

Pension and Postretirement
Assumptions
--------------------------
Assumptions used were:
Discount rate................................ 7.75%
Rate of increase in compensation levels...... 5.00%
Weighted average expected long-term
rate of return on assets................. 9.00%

For purposes of calculating the postretirement benefit obligation, it is assumed
health care costs for covered individuals prior to age 65 will increase by 7.5%
in 2000 and that the rate of increase thereafter will decline by .75% annually
to an ultimate rate of 5.25% by the year 2003. For covered individuals age 65
and older, it is assumed health care costs will increase by 5.5% annually.

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<PAGE>

If the assumed health care trend rates used to measure the expected cost of
benefits covered by the plans were increased by 1.0%, the total service and
interest cost for 1999 would increase by $2.0 million, and the postretirement
benefit obligation at December 31, 1999, would increase by $15.2 million. If the
assumed health care trend rates were to decrease by 1.0%, the total service and
interest cost for 1999 would decrease by $1.6 million and the postretirement
benefit obligation at December 31, 1999, would decrease by $12.1 million.

18. COMMITMENTS AND CONTINGENCIES

DECOMMISSIONING COSTS

Based on site-specific decommissioning studies that include decontamination,
dismantling, site restoration and dry fuel storage cost, MEC's share of expected
decommissioning costs for Cooper and Quad Cities Station, in 1999 dollars, is
$267 million and $255 million, respectively. In Illinois, nuclear
decommissioning costs are included in customer billings through a mechanism that
permits annual adjustments. These costs are reflected in base rates in Iowa
tariffs.

For purposes of developing a decommissioning funding plan for Cooper, Nebraska
Public Power District ("NPPD") assumes that decommissioning costs will escalate
at an annual rate of 4.0%. Although Cooper's operating license expires in 2014,
the funding plan assumes decommissioning will start in 2004, the anticipated
plant shutdown date.

As of December 31, 1999, MEC's share of funds set aside by NPPD in internal and
external accounts for decommissioning was $109.8 million. In addition, the
funding plan also assumes various funds and reserves currently held to satisfy
NPPD bond resolution requirements will be available for plant decommissioning
costs after the bonds are retired in early 2004. The funding schedule assumes a
long-term return on funds in the trust of 6.75% annually. Certain funds will be
required to be invested on a short-term basis when decommissioning begins and
are assumed to earn at a rate of 4.0% annually. MEC makes payments to NPPD
related to decommissioning Cooper. The Cooper decommissioning component of MEC's
payments to NPPD was $9.1 million, for the period from March 12, 1999 through
December 31, 1999 and is included in operating expenses. Earnings from the
internal account and external trust fund, which are recognized by NPPD as the
owner of the plant, are tax exempt and serve to reduce future funding
requirements.

External trusts have been established for the investment of funds for
decommissioning the Quad Cities Station. The total accrued balance as of
December 31, 1999, was $141.6 million and is included in other long-term accrued
liabilities and a like amount is reflected in nuclear decommissioning trust fund
and other marketable securities and represents the fair value of the assets held
in the trusts.

MEC's provision for depreciation included costs for Quad Cities Station nuclear
decommissioning of $8.2 million for the period from March 12, 1999 through
December 31, 1999. The provision charged to expense is equal to the funding that
is being collected in rates. The decommissioning funding component of MEC's
Illinois and Iowa tariffs assumes decommissioning costs, related to the Quad
Cities Station, will escalate at an annual rate of 5.0% and the assumed annual
return on funds in the trust is 6.9%. Earnings, net of investment fees, on the
assets in the trust fund were $1.6 million for the period from March 12, 1999
through December 31, 1999.

NUCLEAR INSURANCE

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

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<PAGE>

The NPPD and ComEd each purchase nuclear liability insurance for Cooper and Quad
Cities Station, respectively, in the maximum available amount of $200 million.
In accordance with the Price-Anderson Amendments Act of 1988, excess liability
protection above that amount is provided by a mandatory industry-wide program
under which the licensees of nuclear generating facilities could be assessed for
liability incurred due to a serious nuclear incident at any commercial nuclear
reactor in the United States. Currently, MEC's aggregate maximum potential share
of an assessment for Cooper and Quad Cities Station combined is $88.1 million
per incident, payable in installments not to exceed $10 million annually.

The property coverage provides for property damage, stabilization and
decontamination of the facility, disposal of the decontaminated material and
premature decommissioning. For Quad Cities Station, ComEd purchases primary and
excess property insurance protection for the combined interests in Quad Cities,
with coverage limits totaling $2.1 billion. For Cooper, MEC and the NPPD
separately purchase primary and excess property insurance protection for their
respective obligations, with coverage limits of $1.375 billion each. This
structure provides that both MEC and the NPPD are covered for their respective
50% obligation in the event of a loss totaling up to $2.75 billion. MEC also
directly purchases extra expense/business interruption coverage for its share of
replacement power and/or other extra expenses in the event of a covered
accidental outage at Cooper or Quad Cities Station. The coverages purchased
directly by MEC, and the property coverages purchased by ComEd, which includes
the interests of MEC, are underwritten by an industry mutual insurance company
and contain provisions for retrospective premium assessments should two or more
full policy-limit losses occur in one policy year. Currently, the maximum
retrospective amounts that could be assessed against MEC from industry mutual
policies for its obligations associated with Cooper and Quad Cities Station
combined, total $11.6 million.

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

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<PAGE>
19. SEGMENT INFORMATION:

The Company has identified four reportable business segments principally based
on geographic area: Domestic electricity generation, foreign electricity
generation (primarily the Philippines), domestic utility operations and foreign
utility operations (primarily the United Kingdom). Information related to the
Company's reportable operating segments are shown below (in thousands).

Year Ended December 31,
---------------------------------------
1999 1998 1997
---------- ----------- -----------
REVENUE:
Domestic generation ........ $ 106,894 $ 583,311 $ 570,587
Foreign generation ......... 210,366 223,650 102,960
Domestic utility ........... 1,811,599 -- --
Foreign utility ............ 2,098,976 1,842,930 1,566,442
---------- ----------- -----------
Segment revenue ............ 4,227,835 2,649,891 2,239,989
Corporate .................. 170,948 32,820 30,922
---------- ----------- -----------
$4,398,783 $ 2,682,711 $ 2,270,911
========== =========== ===========
OPERATING INCOME: (1)
Domestic generation ........ $ 67,936 $ 313,983 $ 301,589
Foreign generation ......... 126,245 142,977 61,131
Domestic utility ........... 271,442 -- --
Foreign utility ............ 201,203 172,772 191,299
---------- ----------- -----------
Segment operating income ... 666,826 629,732 554,019
Corporate .................. 116,416 (10,387) (12,882)
---------- ----------- -----------
$ 783,242 $ 619,345 $ 541,137
========== =========== ===========
CAPITAL EXPENDITURES:
Domestic generation ........ $ 145,255 $ 105,458 $ 58,956
Foreign generation ......... 95,552 204,301 177,813
Domestic utility ........... 203,359 -- --
Foreign utility (2) ........ 202,073 184,631 134,050
---------- ----------- -----------
Segment capital expenditures 646,239 494,390 370,819
Corporate .................. 120 537 9,830
---------- ----------- -----------
$ 646,359 $ 494,927 $ 380,649
========== =========== ===========

(1) Operating income excludes interest expense, net of capitalized interest.
1997 excludes the losses on non-recurring items of $87.0 million and the loss on
equity investment in Casecnan

(2) Capital expenditures at the foreign utility exclude the effect of exchange
rate changes.

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<PAGE>

As of December 31,
------------------------
1999 1998
----------- ----------
IDENTIFIABLE ASSETS:
Domestic generation ....... $ 858,812 $2,458,842
Foreign generation ........ 1,259,463 1,956,387
Domestic utility .......... 5,192,448 --
Foreign utility ........... 2,972,705 3,095,839
----------- ----------
Segment identifiable assets 10,283,428 7,511,068
Corporate ................. 482,924 1,592,456
----------- ----------
$10,766,352 $9,103,524
=========== ==========

LONG-LIVED ASSETS:
Domestic generation ....... $ 595,607 $1,960,433
Foreign generation ........ 996,764 1,275,104
Domestic utility .......... 4,166,595 --
Foreign utility ........... 2,438,877 2,519,615
----------- ----------
Segment long-lived assets . 8,197,843 5,755,152
Corporate ................. 20,991 19,063
----------- ----------
$ 8,218,834 $5,774,215
=========== ==========

The remaining differences from the segment amounts to the consolidated amounts
described as "Corporate" relate principally to the corporate functions including
administrative costs, corporate cash and related interest income as well as the
non-recurring gains on the sales of the qualified facilities and McLeod common
stock, the gain on the Indonesia insurance proceeds and the Berkshire
transaction costs.

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<PAGE>

20. QUARTERLY FINANCIAL DATA (UNAUDITED)

Following is a summary of the Company's quarterly results of operations for the
years ended December 31, 1999 and 1998 (in thousands, except per share amounts):

THREE MONTHS ENDED *
1999: MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
--------- ----------- ------------ -----------

<S> <C> <C> <C> <C>
Operating revenue ..................................... $ 797,885 $ 1,003,602 $ 1,062,560 $ 1,264,690
Total revenue ......................................... 858,018 1,115,442 1,089,917 1,335,406
Total costs and expenses .............................. 781,259 1,004,713 1,000,545 1,255,197
--------- ----------- ----------- -----------
Income before income taxes ............................ 76,759 110,729 89,372 80,209
Provision for income taxes ............................ 26,065 37,227 27,491 2,692
--------- ----------- ----------- -----------
Income before minority interest ....................... 50,694 73,502 61,881 77,517
Minority interest ..................................... 10,903 12,441 12,185 11,394
--------- ----------- ----------- -----------
Income before extraordinary item ...................... 39,791 61,061 49,696 66,123
Extraordinary item, net of tax ........................ (31,520) (5,366) (3,170) (9,385)
--------- ----------- ----------- -----------
Net income attributable to common stockholders ........ $ 8,271 $ 55,695 $ 46,526 $ 56,738
========= =========== =========== ===========

Income per share before extraordinary item ............ $ .67 $ 1.02 $ .82 $ 1.11
Extraordinary item .................................... (.53) (.09) (.05) (.16)
--------- ----------- ----------- -----------
Net income per share .................................. $ .14 $ .93 $ .77 $ .95
========= =========== =========== ===========
Weighted average basic shares outstanding ............. 59,205 60,037 60,592 59,880
========= =========== =========== ===========

Income per share before extraordinary item diluted .... $ .62 $ .91 $ .75 $ 1.00
Extraordinary item - diluted .......................... (.43) (.08) (.05) (.13)
--------- ----------- ----------- -----------
Net income per share - diluted ........................ $ .19 $ .83 $ .70 $ .87
========= =========== =========== ===========
Weighted average diluted shares outstanding ........... 73,244 72,638 71,330 70,615
========= =========== =========== ===========
</TABLE>
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<PAGE>

THREE MONTHS ENDED *
1998: MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
--------- ----------- ------------ -----------
<S> <C> <C> <C> <C>
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 principal .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
principle - 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
========= =========== =========== ===========
</TABLE>

* The Company's operations are seasonal in nature.

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<PAGE>

INDEPENDENT AUDITORS' REPORT

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

We have audited the accompanying consolidated balance sheets of MidAmerican
Energy Holdings Company and subsidiaries (the "Company") as of December 31, 1999
and 1998, and the related consolidated statements of operations, stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 1999. Our audit also included the financial statement schedule listed in the
Index at Item 14. These financial statements and financial statement schedule
are the responsibility of the Company's management. Our responsibility is to
express an opinion on the financial statements and financial statement schedule
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 as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting principles.
Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.

DELOITTE & TOUCHE LLP
Des Moines, Iowa
January 25, 2000
(March 14, 2000 as to Note 3)

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<PAGE>

MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
as of December 31, 1999 and 1998
(dollars in thousands)

1999 1998
----------- -----------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents .................................... $ 240,938 $ 1,522,294
----------- -----------
Total current assets ....................................... 240,938 1,522,294

Investments in and advances to subsidiaries and joint ventures 2,972,843 2,430,734
Equipment, net ............................................... 16,728 17,554
Deferred charges and other assets ............................ 158,887 155,332
----------- -----------

Total assets ............................................... $ 3,389,396 $ 4,125,914
=========== ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and other accrued liabilities ............... $ 88,490 $ 98,940
----------- -----------
Total current liabilities .................................. 88,490 98,940

Parent company debt ............................................. 1,856,318 2,645,991
----------- -----------

Total liabilities ............................................ 1,944,808 2,744,931
----------- -----------

Company-obligated mandatorily redeemable
convertible preferred securities of subsidiary trusts ........ 450,000 553,930

Stockholders' equity:
Preferred stock - authorized 2,000 shares, no par value ...... -- --
Common stock -authorized 180,000 shares, no par value
issued 82,980 shares, 59,944 and 59,605 shares, respectively -- --
Additional paid in capital ................................... 1,249,079 1,238,690
Retained earnings ............................................ 507,726 340,496
Accumulated other comprehensive income ....................... (12,029) 45
Treasury stock - 23,036 and 23,375 common shares,
respectively, at cost ...................................... (750,188) (752,178)
----------- -----------
Total stockholders' equity ................................... 994,588 827,053
----------- -----------
Total liabilities and stockholders' equity ................... $ 3,389,396 $ 4,125,914
=========== ===========

</TABLE>

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

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<PAGE>

MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I
PARENT COMPANY ONLY (CONTINUED)
CONDENSED STATEMENTS OF OPERATIONS
for the three years ended December 31, 1999
(dollars and shares in thousands, except per share amounts)

1999 1998 1997
--------- --------- ----------
<S> <C> <C> <C>
Revenue:

Equity in undistributed earnings of subsidiary companies
and joint ventures ......................................... $ 159,439 $ 205,049 $ 79,905
Cash dividends and distributions from subsidiary
companies and joint ventures ............................... 345,430 179,782 156,686
Interest and other income ..................................... 34,002 44,686 49,488
--------- --------- ---------

Total revenues ............................................. 538,871 429,517 286,079
--------- --------- ---------

Expenses:

General and administration .................................... 40,262 30,527 36,616
Interest, net of capitalized interest ......................... 156,600 132,250 75,438
--------- --------- ---------

Total expenses ............................................. 196,862 162,777 112,054
--------- --------- ---------

Income before provision for income taxes ...................... 342,009 266,740 174,025
Provision for income taxes .................................... 93,475 93,265 99,044
--------- --------- ---------

Income before minority interest ............................... 248,534 173,475 74,981
Minority interest ............................................. 31,863 35,963 23,158
--------- --------- ---------

Income before extraordinary items and cumulative effect of
change in accounting principle ............................. 216,671 137,512 51,823
Extraordinary items, net of tax ............................... (49,441) (7,146) (135,850)
Cumulative effect of change in accounting principle, net of tax -- (3,363) --
--------- --------- ---------
Net income (loss) available to common stockholders ............ $ 167,230 $ 127,003 $ (84,027)
========= ========= =========

Income per share before extraordinary items and cumulative
effect of change in accounting principle ................... $ 3.62 $ 2.29 $ .77
Extraordinary items ........................................... (.83) (.12) (2.02)
Cumulative effect of change in accounting principle ........... -- (.06) --
--------- --------- ---------
Net income (loss) per share ................................... $ 2.79 $ 2.11 $ (1.25)
========= ========= =========

Income per share before extraordinary items and cumulative
effect of change in accounting principle - diluted ......... $ 3.28 $ 2.15 $ .75
Extraordinary items - diluted ................................. (.69) (.10) (1.97)
Cumulative effect of change in accounting principle - diluted . -- (.04) --
--------- --------- ---------
Net income (loss) per share - diluted ......................... $ 2.59 $ 2.01 $ (1.22)
========= ========= =========

Average number of shares outstanding .......................... 59,929 60,139 67,268
========= ========= =========
Diluted shares ................................................ 71,948 74,100 68,686
========= ========= =========

</TABLE>

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

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<PAGE>

MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I
PARENT COMPANY ONLY (continued)
CONDENSED STATEMENTS OF CASH FLOWS
for the three years ended December 31, 1999
(dollars in thousands)

1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Cash flows from operating activities ................ $ (261,276) $ (219,705) $ (200,057)
----------- ----------- -----------

Cash flows from investing activities:
Decrease (increase) in advances to and investments in
subsidiaries and joint ventures .................. (53,215) (103,494) 174,584
Decrease (increase) in short-term investments ....... -- 421 (229)
Other ............................................... (4,390) (24,749) 18,330
----------- ----------- -----------

Cash flows from investing activities ................ (57,605) (127,822) 192,685
----------- ----------- -----------

Cash flows from financing activities:
Proceeds from sale of common and treasury stock
and exercise of stock options .................... 5,482 3,412 703,624
Proceeds from issuance of parent company debt ....... -- 1,502,243 350,000
Proceeds from convertible preferred securities
of subsidiary trusts ............................. -- -- 450,000
Repayment of parent company debt .................... (853,420) (167,285) (100,000)
Net proceeds from revolver .......................... -- -- (95,000)
Purchase of treasury stock .......................... (104,847) (724,791) (55,505)
Deferred charges relating to debt financing ......... (9,690) (24,235) (33,719)
----------- ----------- -----------

Cash flows from financing activities ................ (962,475) 589,344 1,219,400
----------- ----------- -----------

Net increase (decrease) in cash and cash equivalents (1,281,356) 241,817 1,212,028

Cash and cash equivalents at beginning of period .... 1,522,294 1,280,477 68,449
----------- ----------- -----------

Cash and cash equivalents at end of period .......... $ 240,938 $ 1,522,294 $ 1,280,477
=========== =========== ===========
Supplemental disclosures:
Interest paid (net of amount capitalized) ........... $ 173,285 $ 104,350 $ 38,176
=========== =========== ===========

Income taxes paid ................................... $ 83,280 $ 32,100 $ 35,302
=========== =========== ===========
</TABLE>

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

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<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, 2000.

MIDAMERICAN ENERGY HOLDINGS COMPANY

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

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

Signature Date
--------- ----

/s/ David L. Sokol* March 30, 2000
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and
Director

/s/ Gregory E. Abel* March 30, 2000
Gregory E. Abel
President, Chief Operating Officer and Director

/s/ Patrick J. Goodman* March 30, 2000
Patrick J. Goodman
Senior Vice President and
Chief Financial Officer

/s/ Edgar D. Aronson* March 30, 2000
Edgar D. Aronson
Director

/s/ Stanley J. Bright * March 30, 2000
Stanley J. Bright
Director

/s/ Walter Scott, Jr.* March 30, 2000
Walter Scott, Jr.
Director

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<PAGE>

/s/ Marc D. Hamburg * March 30, 2000
Marc D. Hamburg
Director

/s/ Warren Buffett* March 30, 2000
Warren Buffett
Director

/s/ John Boyer* March 30, 2000
John Boyer
Director

/s/ W. David Scott* March 30, 2000
W. David Scott
Director

*By:/s/ Steven A. McArthur March 30, 2000
Steven A. McArthur
Attorney-in-Fact

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<PAGE>

EXHIBIT INDEX

3.1* Restated Articles of Incorporation of the Company.

3.2* Bylaws of the Company.

4.2 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).

4.3 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).

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

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

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

4.7 Form of Second Supplemental Indenture, 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.)

4.8 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).

4.9* Indenture, dated as of March 14, 2000, among the Company and the Bank
of New York, as Trustee.

4.10* Subscription Agreement executed by Berkshire Hathaway Inc. dated as of
March 14, 2000.

10.1* Employment Agreement between the Company and David L. Sokol, dated May
10, 1999.

10.2* Amendment No. 1 to the Amended and Restated Employment Agreement
between the Company and David L. Sokol, dated March 14, 2000.

10.3* Amended and Restated Employment Agreement between the Company and
Gregory E. Abel, dated May 10, 1999.

10.4* Amended and Restated Employment Agreement between the Company an
Steven A. McArthur, dated May 10, 1999.

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<PAGE>

10.5* Employment Agreement between the Company and Patrick J. Goodman, dated
May 10, 1999.

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 Agreemen
dated February 18, 1994 and the Fourth Amendment to 25 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 (incor-
porated by reference to Exhibit 10.97 to the Company's 1994 Form
10-K).

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 refer-
ence 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 SavingsAssocia-
tion 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 Geotherma
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 Geo-
thermal Power Company, Inc. and Overseas Private Investment Corpora-
tion (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 Geo-
thermal 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).

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<PAGE>

10.20 231 MW Power Plant - Malitbog Agreement ("Malitbog ECA") dated Sep-
tember 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 Ban
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 Geo-
thermal 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).

10.24 Overseas Private Investment Corporation Contract of Insurance dated
December 21, 1994 between OPIC and Magma Netherlands, B.V. (incor-
porated 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 refer-
ence 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 th
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

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<PAGE>

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 Com-
pany's 1996 Form 10-K).

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

10.34 Acquisition Agreement by and between CalEnergy Company, Inc. an
Kiewit Diversified Group Inc. dated as of September 10, 1997 (incor-
porated 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., MidAmeri-
can 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 (incorporated by reference to the Company's 1998
Form 10-K).

10.37 Settlement Agreement by and between MidAmerican Energy Company, the
Iowa Utilities Board, the Iowa Office of Consumer Advocate, and
others (incorporated by reference to the Company's 1998 Form 10-K).

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. (incorporated by reference to 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. (incorporated by reference to 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. (incorporated by reference to 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. (incorporated by reference to 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.
(incorporated by reference to 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, betwee
Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee.
(incorporated by reference to Exhibit 4.6 to Midwest Resources'
Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-10654.)

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<PAGE>

10.44 Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947.
(incorporated by reference to 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. (incorporated
by reference to Iowa-Illinois as Exhibit 2.08 to Commission File No.
2-28806.)

10.46 Twentieth Supplemental Indenture dated as of May 1, 1982. (incorpor-
ated by reference to 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. (inco-
porated by reference to Iowa-Illinois as Exhibit 4.B.30 to Commissio
File No. 33-39211.)

10.48 Twenty-Eighth Supplemental Indenture dated as of May 15, 1992. (incor-
porated by reference to 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.
(incorporated by reference to 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. (incor-
porated by reference to Exhibit 4.34.A to Iowa-Illinois' Current
Report on Form 8-K dated October 7, 1993, Commission File No. 1-3573.)

10.51 Sixth Supplemental Indenture dated as of July 1, 1995, between Midwest
Power Systems Inc. and Harris Trust and Savings Bank, Trustee.
(incorporated by reference to Exhibit 4.15 to 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. (incorporated by reference to Exhibit 4.16 to Mid-
American 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. (incorporated by reference to
Exhibit 4-C-2 to Iowa Power Inc.'s (IPR) Registration Statement, Reg-
istration No. 2-27681).

10.54 Amendments Nos. 1 and 2 to Power Sales Contract between Iowa Power
Inc. and Nebraska Public Power District. (incorporated by reference
to 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. (incorporated by reference to 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. (incorporated by reference to 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. (incorporated by reference to 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.)

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<PAGE>

10.58 MidAmerican Energy Company Severance Plan For Specified Officers
dated November 1, 1996. (incorporated by reference to 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 Holdings Company Executive Voluntary Deferred
Compensation Plan.

10.60* MidAmerican Energy Company Supplemental Retirement Plan for Designated
Officers. (incorporated by reference to Exhibit 10.3 to MidAmerican
Energy's Annual Report on Form 10-K dated December 31, 1995, Commis-
sion File No. 1-11505.)

10.61* MidAmerican Energy Company Restated Executive Deferred Compensation
Plan.

10.62* MidAmerican Energy Holdings Company Restated Deferred Compensation
Plan - Board of Directors.

10.63* MidAmerican Energy Company Combined Midwest Resources/Iowa Resources
Restated Deferred Compensation Plan - Board of Directors.

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

10.72 Supplement Retirement Plan for Principal Officers, as amended as o
July 1, 1993. (incorporated by reference to 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. (incorporated by reference to 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. (incorporated by
reference to 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. (incorporated by reference to Exhibit 10.24 to Midwest
Resources' Annual Report on Form 10-K for the year ended December 31,
1994, Commission File No. 1-10654.)

10.78 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. (incorporated by reference to Exhibit 10.2
to MidAmerican Energy's Quarterly Reports on the combined Form 10- for
the quarter ended September 30, 1997, Commission File Nos. 1-12459 and
1-11505, respectively.)

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.

-107-

Exhibit 21
MIDAMERICAN ENERGY HOLDINGS COMPANY

SUBSIDIARIES AND JOINT VENTURES

Subsidiaries:

MIDAMERICAN FUNDING LLC Iowa
IPP CO Delaware
IPP CO LLC Delaware
CE MINERALS DEVELOPMENT LLC Delaware
CALENERGY HOLDINGS INC. Delaware
CE TEXAS ENERGY LLC Delaware
CE TEXAS GAS LP Delaware
FISH LAKE POWER LLC Delaware
IMPERIAL MAGMA LLC Delaware
SALTON SEA ROYALTY LLC Delaware
VPC GEOTHERMAL LLC Delaware
CALENERGY CAPITAL TRUST I Delaware
CALENERGY CAPITAL TRUST II Delaware
CALENERGY CAPITAL TRUST III Delaware
CALENERGY CAPITAL TRUST IV Delaware
CALENERGY CAPITAL TRUST V Delaware
CALENERGY CAPITAL TRUST VI Delaware
CE GEOTHERMAL, INC. Delaware
WESTERN STATES GEOTHERMAL COMPANY Delaware
INTERMOUNTAIN GEOTHERMAL COMPANY Delaware
CALIFORNIA ENERGY DEVELOPMENT CORPORATION Delaware
CALIFORNIA ENERGY YUMA CORPORAITON Utah
CE EXPLORATION COMPANY Delaware
CE NEWBERRY, INC. Delaware
CALENERGY INTERNATIONAL SERVICES, INC. Delaware
CALIFORNIA ENERGY GENERAL CORPORATION Delaware
CE GENERATION LLC Nebraska
CE INTERNATIONAL INVESTMENTS, INC. Delaware
CE MAHANAGDONG LTD. Bermuda
CE LUZON GEOTHERMAL POWER COMPANY, INC. Philippines
CE PHILIPPINES LTD. Bermuda
ORMOC CEBU LTD. Bermuda
CE CEBU GEOTHERMAL POWER COMPANY, INC. Philippines
CE INDONESIA LTD. Bermuda
BALI ENERGY LTD. Bermuda
CE CASECNAN LTD. Bermuda

-1-
<PAGE>

CE SINGAPORE LTD. Bermuda
CALENERGY INTERNATIONAL LTD. Bermuda
CE CASECNAN WATER AND ENERGY COMPANY, INC. Philippines
CE BALI LTD. Bermuda
CE ASIA LTD. Bermuda
MAGMA POWER COMPANY Nevada
DESERT VALLEY COMPANY California
VULCAN POWER COMPANY Nevada
CALENERGY OPERATING CORPORATION Delaware
SALTON SEA POWER COMPANY Nevada
MAGMA LAND COMPANY I Nevada
MAGMA GENERATING COMPANY II Nevada
MAGMA GENERATING COMPANY I Nevada
CALIFORNIA ENERGY MANAGEMENT COMPANY Delaware
SALTON SEA FUNDING CORPORATION Delaware
TONGONAN POWER INVESTMENT, INC. Philippines
MAGMA NETHERLANDS B.V. Netherlands
NORMING INVESTMENTS B.V. Netherlands
CALENERGY IMPERIAL VALLEY COMPANY, INC. Delaware
SLUPO I B.V. Netherlands
CONEJO ENERGY COMPANY California
NIGUEL ENERGY COMPANY California
SAN FELIPE ENERGY COMPANY California
FALCON SEABOARD RESOURCES, INC. Texas
FALCON SEABOARD OIL COMPANY Texas
FALCON SEABOARD PIPELINE CORPORATION Texas
FALCON SEABOARD POWER CORPORATION Texas
POWER RESOURCES, LTD Texas
BIG SPRING PIPELINE COMPANY Texas
SECI HOLDINGS, INC. Delaware
FALCON POWER OPERATING COMPANY Texas
NORCON HOLDINGS, INC. Delaware
SARANAC ENERGY COMPANY, INC. Delaware
NORTHERN CONSOLIDATED POWER, INC. Delaware
NORTH COUNTRY GAS PIPELINE CORPORATION New York
CE POWER, INC. Delaware
CE ELECTRIC, INC. Delaware
CE ELECTRIC UK plc England/Wales
NORTHERN ELECTRIC PLC England/Wales
NORTHERN ELECTRIC GENERATION LIMITED England/Wales
NORTHERN ELECTRIC (OVERSEAS HOLDINGS) LIMITED England/Wales
NORTHERN ELECTRIC PROPERTIES LIMITED England/Wales
NORTHERN ELECTRIC FINANCE PLC England/Wales

-2-
<PAGE>

NORTHERN TRACING AND COLLECTION SERVICES LIMITED England/Wales
GAS UK LIMITED England/Wales
CALENERGY GAS (HOLDINGS) LIMITED England/Wales
NORTHERN ELECTRIC SHARE SCHEME TRUSTEE LIMITED England/Wales
NORTHERN TRANSPORT FINANCE LIMITED England/Wales
NORTHERN ELECTRIC RETAIL LIMITED England/Wales
NORTHERN ELECTRIC DISTRIBUTION LIMITED England/Wales
NORTHERN ELECTRIC SUPPLY LIMITED England/Wales
NORTHERN METERING SERVICES LIMITED England/Wales
NORTHERN UTILITY SERVICES LIMITED England/Wales
NORTHERN ELECTRIC TELECOM LIMITED England/Wales
NORTHERN ELECTRIC TRANSPORT LIMITED England/Wales
NORTHERN INFOCOM LIMITED England/Wales
NORTHERN ELECTRIC TRAINING LIMITED England/Wales
NORTHERN ELECTRIC GENERATION (TPL) LIMITED England/Wales
NORTHERN ELECTRIC GENERATION (CPS) LIMITED England/Wales
NORTHERN ELECTRIC GENERATION (NPL) LIMITED England/Wales
NORTHERN ELECTRIC GENERATION (PEAKING) LIMITED England/Wales
NORTHERN ELECTRIC INSURANCE SERVICES LIMITED Isle of Man
CALENERGY GAS (UK) LIMITED England/Wales
CE INDONESIA GEOTHERMAL, INC. Delaware
NEPTUNE POWER LTD England/Wales
CALENERGY GAS (POLSKA) SP. Z O.O. Poland
CE (BERMUDA) FINANCING LTD. Bermuda
CALENERGY GAS (PIPELINES) LIMITED England/Wales
CALENERGY POWER POLSKA SP. Z O.O. Poland
SALTON SEA POWER L.L.C. Delaware
KIEWIT ENERGY PACIFIC HOLDINGS CORP. Delaware
KIEWIT ENERGY U.K. INC. Delaware
KIEWIT ENERGY INTERNATIONAL (BERMUDA) LTD. Bermuda
CE SALTON SEA INC. Delaware
AURORA 2000, L.L.C. Delaware
CE AURORA I, INC. Delaware
NORTHERN AURORA, INC. Delaware
CALENERGY MINERALS LLC Delaware
YUMA COGENERATION ASSOCIATES Utah
VULCAN/BN GEOTHERMAL POWER COMPANY Nevada
LEATHERS, L.P. California
ELMORE, L.P. California
DEL RANCH, L.P. (HOCH) California

-3-
<PAGE>

SALTON SEA BRINE PROCESSING, L.P. California
SALTON SEA POWER GENERATION L.P. California
VISAYAS GEOTHERMAL POWER COMPANY Philippines
SARANAC POWER PARTNERS, L.P. Delaware
NORCON POWER PARTNERS, L.P. Delaware
CE ELECTRIC UK HOLDINGS England/Wales
VIKING POWER LTD England/Wales
CE ELECTRIC UK FUNDING COMPANY England/Wales
MHC INC. Iowa
MIDAMERICAN ENERGY COMPANY Iowa
THE REFERRAL COMPANY Iowa
SELECT RELOCATION SERVICES, INC. Iowa
EDINA REALTY MORTGAGE, LLC Delaware
CBSHOME REAL ESTATE COMPANY Nebraska
MIDAMERICAN HOME SERVICES MORTGAGE, LLC Iowa
TITLE INFORMATION SERVICES, LLC Minnesota
QUAD CITIES ENERGY COMPANY Iowa
CORDOVA ENERGY COMPANY LLC Iowa
MIDWEST GAS COMPANY Iowa
DCCO, INC. Minnesota
INTERCOAST SIERRA POWER COMPANY Delaware
MIDAMERICAN ENERGY FINANCING II Delaware
BETTENDORF LOCK & SECURITY SERVICES, INC. Iowa
SUTTON SECURITY, INC. Nebraska
PRO-TEC ALARM SYSTEMS AND SERVICES, INC. Missouri
CBS BROKERAGE SYSTEMS, INC Nebraska
CBEC RAILWAY INC. Iowa
MIDAMERICAN ENERGY FINANCING I Delaware
MIDAMERICAN ENERGY FUNDING CORPORATION Delaware
MIDAMERICAN CAPITAL COMPANY Delaware
MHC INVESTMENT COMPANY South Dakota
MWR CAPITAL INC. South Dakota
MIDWEST CAPITAL GROUP, INC. Iowa
DAKOTA DUNES DEVELOPMENT COMPANY Iowa
TWO RIVERS INC. South Dakota
MIDAMERICAN SERVICES COMPANY Iowa
NORTHERN ELECTRIC & GAS LIMITED United Kingdom
NORTHERN ELECTRIC INVESTMENTS LIMITED United Kingdom
CALENERGY EUROPE LIMITED United Kingdom
NORTHERN AURORA LIMITED United Kingdom
RYHOPE ROAD DEVELOPMENTS LTD. United Kingdom
KINGS ROAD DEVELOPMENTS LIMITED United Kingdom
SEAL SANDS NETWORK LTD. United Kingdom

-4-
<PAGE>

TEESSIDE POWER LIMITED United Kingdom
KIRKHEATON WIND LIMITED United Kingdom
VEHICLE LEASE AND SERVICE LIMITED United Kingdom
CE TURBO LLC Delaware
CE TEXAS FUEL, LLC Delaware
CE TEXAS POWER, LLC Delaware
CE TEXAS PIPELINE, LLC Delaware
CE TEXAS RESOURCES, LLC Delaware
CE ADMINISTRATIVE SERVICES, INC. Delaware
AMERICAN PACIFIC FINANCE COMPANY Delaware
CALENERGY COMPANY, INC. Delaware
SALTON SEA MINERALS CORP. Delaware
CALENERGY INTERNATIONAL, INC. Delaware
CORDOVA FUNDING CORPORATION Delaware
GILBERT/CBE INDONESIA L.L.C. Nebraska

-5-

Exhibit 23

INDEPENDENT AUDITORS' CONSENT

We consent to the incorporation by reference in Registration Statements No.
33-51363, No. 333-32821 and No. 333-62697 on Form S-3 of MidAmerican Energy
Holdings Company of our report dated January 25, 2000 (March 14, 2000 as to Note
3) appearing in the Annual Report on Form 10-K of MidAmerican Energy Holdings
Company for the year ended December 31, 1999.

Des Moines, Iowa
March 30, 2000

Exhibit 24

POWER OF ATTORNEY
-----------------

The undersigned, a member of the Board of Directors or an 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, 1999 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.

Executed as of March 29, 2000

/s/ David L. Sokol /s/ Gregory E. Abel
- ------------------------------------ -----------------------------------
DAVID L. SOKOL GREGORY E. ABEL

/s/ Patrick J. Goodman /s/ Stanley J. Bright
- ------------------------------------ -----------------------------------
PATRICK J. GOODMAN STANLEY J. BRIGHT

/s/ Edgar D. Aronson /s/ Walter Scott Jr.
- ------------------------------------ -----------------------------------
EDGAR D. ARONSON WALTER SCOTT, JR.

/s/ Warren Buffett
- ------------------------------------ -----------------------------------
RICHARD R. JAROS WARREN BUFFETT

/s/ Marc D. Hamburg /s/ W. David Scott
- ------------------------------------ -----------------------------------
MARC D. HAMBURG W. DAVID SCOTT

/s/ John Boyer
- ------------------------------------
JOHN BOYER

<ARTICLE> 5
<CIK> 0001081316
<NAME> MIDAMERICAN ENERGY HOLDINGS COMPANY
<MULTIPLIER> 1,000

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