2
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, 1997
Commission File No. 1-9874
CALENERGY COMPANY, INC.
(Exact name of registrant as specified in its charter)
Delaware 94-2213782
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
302 S. 36th Street, Suite 400, Omaha, NE 68131
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (402) 341-4500
Securities registered pursuant to Section 12(b) of the Act:
Name of exchange
Title of each class on which registered
Common Stock, $0.0675 New York Stock Exchange
par value ("Common Stock") Pacific Stock Exchange
London Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: N/A
Indicate by check mark whether the Registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the Registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days:
Yes X No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of Registrant's
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ X ]
Based on the closing sales price of Common Stock on the New
York Stock Exchange on March 23, 1998 the aggregate market value
of the Common Stock held by non-affiliates of the Company was
$1,865,191,447.
60,411,059 shares of Common Stock were outstanding on March 23, 1998.
TABLE OF CONTENTS
PART I 1
ITEM 1. BUSINESS 1
GENERAL 1
RECENT SUCCESSFUL ACQUISITIONS 1
STRATEGY 2
THE GLOBAL ENERGY MARKET 4
THE UNITED STATES 6
THE UNITED KINGDOM 6
THE PHILIPPINES 8
THE COMPANY'S DISTRIBUTION AND SUPPLY BUSINESS 8
POWER GENERATION PROJECTS 10
PROJECTS IN OPERATION 10
PROJECTS IN CONSTRUCTION 11
PROJECTS WITH SIGNED POWER SALES CONTRACTS OR AWARDED
DEVELOPMENT RIGHTS 12
PROJECTS IN OPERATION 13
UNITED STATES OPERATIONS 13
U.S. GAS PROJECTS 16
OTHER U.S. GEOTHERMAL OPERATIONS 18
UNITED KINGDOM OPERATIONS AND CONSTRUCTION 18
THE PHILIPPINES OPERATIONS AND CONSTRUCTION 18
INDONESIA OPERATIONS AND CONSTRUCTION 22
PROJECTS IN DEVELOPMENT 23
UNITED STATES 23
UNITED KINGDOM 24
PHILIPPINES 24
INDONESIA 25
PRODUCING GAS FIELD OPERATIONS AND FIELDS IN DEVELOPMENT 25
THE COMPANY'S PRODUCING GAS FIELD OPERATIONS AND FIELDS IN
DEVELOPMENT 25
FIELDS IN DEVELOPMENT 26
REGULATORY, ENERGY AND ENVIRONMENTAL MATTERS 27
UNITED STATES 27
UNITED KINGDOM 28
EMPLOYEES 28
ITEM 2. PROPERTIES 29
ITEM 3. LEGAL PROCEEDINGS 29
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 29
PART II 30
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER'S MATTERS 30
ITEM 6. SELECTED FINANCIAL DATA 31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATION 31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 31
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 31
PART III 32
MANAGEMENT 32
ITEM 10. DIRECTORS, EXECUTIVE AND OTHER OFFICERS OF THE COMPANY32
PART IV 38
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K 38
SIGNATURES 40
EXHIBIT INDEX 62
DOCUMENTS INCORPORATED BY REFERENCE
Incorporated by reference into this Form 10-K, in response to
Item 3 Part I, Items 6 through 8 of Part II and Items 10 through
13 of Part III, are the portions indicated herein of (i) the
annual report of CalEnergy Company, Inc. (the "Company") to
security holders for the fiscal year ended December 31, 1997 (the
"Annual Report"), and (ii) the Company's proxy statement dated on
or about April 3, 1998 for the annual meeting of stockholders to
be held on May 21, 1998 (the "Proxy Statement").
PART I
Item 1. Business
General
CalEnergy Company, Inc. (the "Company") is a fast-growing global
power company whose goal is to be a leading provider of low cost and
reliable energy services throughout the world as governments privatize
or deregulate electricity and gas markets. The Company was founded in
1971 and, through its subsidiaries, manages and owns interests in over
5,000 megawatts ("MW") of power generation facilities in operation,
construction and development worldwide, including 20 generating
facilities which it currently operates. In addition, through its
subsidiary, Northern Electric plc ("Northern"), the Company is engaged
in the distribution of electricity to approximately 1.5 million
customers primarily in northeast England as well as the supply of
electricity and gas (together with other related business activities)
throughout England and Wales. The Company has achieved significant
growth in earnings and assets over the past five years through: (i)
acquisitions that complement and diversify the Company's existing
business, broaden the geographic locations of and fuel sources used by
its projects and enhance its competitive capabilities; (ii) enhancement
of the financial and technical performance of existing and acquired
projects; and (iii) development and construction of new plants and
facilities ("greenfield development").
The market capitalization of the Company has risen at a compound
annual rate of 28% from approximately $656 million in December 1993 to
approximately $1.9 billion in March 1998, the revenues of the Company
have risen at a compound annual rate of 130% from approximately $186
million in 1994 to approximately $2.2 billion in 1997 and net income
available to common stockholders excluding non-recurring and
extraordinary items has risen at a compound annual rate of 60% from
approximately $34 million in 1994 to approximately $139 million in
1997. From 1994 through 1997, the Company's EBITDA and total assets
have increased by a compound annual growth rate of 84% and 88%,
respectively. EBITDA for the year ended December 31, 1997 was $811
million before a non-recurring item. "EBITDA" means the Company's
earnings, before interest, taxes, depreciation and amortization.
Information concerning EBITDA is presented here not as a measure of
operating results, but rather as a measure of the Company's ability to
service debt. EBITDA should not be construed as an alternative to
either (i) operating income (determined in accordance with Generally
Accepted Accounting Principles ("GAAP")) or (ii) cash flow from
operating activities (determined in accordance with GAAP). In this
Annual Report, references to "U.S. dollars," "dollars," "US $," "$" or
"cents" are to the currency of the United States and references to "
pounds sterling," "pounds," "sterling," "pounds sterling," "pence" or
"p" are to the currency of the United Kingdom.
The Company's Common Stock is traded on the New York, Pacific and
London Stock Exchanges. The principal executive offices of the Company
are located at 302 South 36th Street, Suite 400, Omaha, Nebraska 68131
and its telephone number is (402) 341-4500. The Company was
incorporated in 1971 under the laws of the State of Delaware.
Recent Successful Acquisitions
In the last three years, the Company has consummated several
significant acquisitions, which have been successfully integrated and
immediately accretive to earnings. In January 1995, the Company
acquired Magma Power Company ("Magma"), a publicly-traded United States
independent power producer with 228 net MW of operating capacity and
154 net MW of ownership capacity, for approximately $958 million. The
Magma acquisition, combined with the Company's previously existing
assets, made the Company the world's largest independent geothermal
power producer (based on the Company's estimate of aggregate MW of
electric generating capacity in operation and construction).
In April 1996, the Company completed the purchase for
approximately $70 million of its partner's interests in four electric
generating plants in Southern California, resulting in sole ownership
of the Imperial Valley Projects' 228 net MW of aggregate operating
capacity.
In August 1996, the Company acquired Falcon Seaboard Resources,
Inc. ("Falcon Seaboard") for approximately $226 million, thereby
acquiring significant ownership in 520 net MW of natural gas-fired
electric production facilities located in New York, Texas and
Pennsylvania and a related gas transmission pipeline.
In December 1996, the Company acquired a majority of the common
shares of Northern. Northern is one of the twelve regional electricity
companies (each, a "REC") which came into existence as a result of the
restructuring and subsequent privatization of the electricity industry
in the United Kingdom ("U.K.") in 1990. Northern distributes
electricity in its authorized area located in northeast England which
covers approximately 14,400 square kilometers and has a population of
approximately 3.2 million people. Northern also supplies electricity
and gas inside and outside its authorized area and currently owns
interests in four producing gas field operations in the North Sea.
On September 11, 1997, the Company signed a definitive agreement
with Kiewit Diversified Group Inc. ("KDG"), a wholly-owned subsidiary
of Peter Kiewit Sons', Inc. ("PKS"), to acquire all of KDG's ownership
interest in Northern and the various other international power
generation projects and development opportunities (the "Energy Project
Joint Venture Acquisition") which were jointly owned with, and managed
by, the Company, as well as to repurchase all of KDG's outstanding
ownership interests in the Company's Common Stock (the "Stock
Repurchase," and together with the Energy Project Joint Venture
Acquisition, the "KDG Acquisition"). The Company completed the KDG
Acquisition on January 2, 1998.
KDG's ownership interest in the Company consisted of 20,231,065
shares of Common Stock (including options to acquire 1,000,000 shares
of Common Stock) which represented approximately 30% of the Company's
then outstanding shares (26% on a fully diluted basis), a 30% interest
in Northern and the following power project interests: 45% of the 165
net MW Mahanagdong project, 35% of the 150 net MW Casecnan project, 47%
of the 400 net MW Dieng project, 44% of the 400 net MW Patuha project,
and 30% of the 400 net MW Bali project. The Company is the managing
partner and operator of each such project (collectively, the "Joint
Venture Energy Projects"). In addition, KDG's 50% interest in all other
power project opportunities which the Company had in development under
the international joint venture agreement with KDG were transferred to
the Company. The Company immediately added over 1,000 net MW of
generating capacity in operation, construction and development to its
project portfolio (including approximately 850 net MW of operating,
construction and advanced stage development projects).
The Company paid $1,159 million for KDG's ownership interest in
Northern, the Joint Venture Energy Projects and the Company's Common
Stock. The Company funded the KDG Acquisition with available cash, the
net proceeds from the issuance of 19.1 million shares of Common Stock
which closed on October 17, 1997 and the proceeds of an offering of
7.63% Senior Notes due 2007 which closed on October 28, 1997. These
debt securities are senior unsecured obligations of the Company ranking
pari passu in right of payment with all other existing and future
senior unsecured obligations of the Company and will rank senior to all
other existing and future subordinated debt of the Company.
Strategy
The Company's growth strategy remains focused upon taking
advantage of the investment opportunities created by the continuing
deregulation and privatization in energy sectors throughout the world.
In order to effectively execute its growth strategy, the Company has
organized its operations into a functional structure. The functional
alignment is believed to allow for greater efficiencies in operations
and better coordination and asset utilization in developing the
Company's business.
The Company's strategy is comprised of the following key elements:
o Growth through international and domestic acquisitions. The
Company has successfully completed five acquisitions in the past three
years, each of which was immediately accretive to earnings. The Company
believes several of these acquisitions provided it with specialized
skills and experience that enhance its competitive position in the
areas it has targeted for future growth. For example, the Company's
acquisition of Northern, a U.K. regional electricity company engaged in
electricity distribution and supply and gas supply and related
businesses, is the first step in its planned expansion into those
sectors in the U.S. and elsewhere throughout the world. In addition,
since the U.K. is progressively deregulating its electricity and gas
supply sectors, the Company believes that its Northern management team
has the knowledge and skills to compete in a competitive supply market.
Northern also possesses the sophisticated billing and proprietary
information systems that are believed by the Company to be critically
important components of the skill and technology base necessary to
compete effectively in a deregulated environment.
The Company believes that the electricity industry in the U.S. will
also progressively deregulate over the next three to
five years and will largely follow the regulatory model established in
the U.K. (with incentive based rates or price caps). As currently
regulated U.S. electricity distributors and electricity and gas
suppliers attempt to rationalize their businesses to maintain
profitability in a price competitive market, the Company believes that
opportunities will become available to low cost and reliable providers
of energy services to gain market share in energy supply and provide
additional services to competitors (such as utility line construction
and maintenance services, metering, customer billing and information
systems services). As a result, the Company believes that by acquiring
a U.S. utility operation and transferring the knowledge, skills and
systems gained at Northern, it can create a platform from which a U.S.
energy distribution and supply business can be profitably established
and expanded in a deregulated market. Consistent with its disciplined
approach to acquisitions, the Company will continue to evaluate U.S.
utility available opportunities from time to time, although it
currently has no specific acquisition plans.
o Growth through greenfield development of 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. In the past three years, the Company has developed and
financed seven new international power projects, three of which have
already completed construction on schedule and within budget and are
now earning revenues and the remaining four of which are still in the
construction phase. With the acquisition of Sovereign Exploration Ltd.
(now CalEnergy Gas UK) as part of the Northern acquisition, the Company
has expanded its development strategy to include integrated generation
and upstream natural gas operations. The addition of gas exploration,
production and technical storage capabilities allows the Company to
expand its number of target markets throughout the world. In addition,
utilization of its geotechnical expertise in this manner allows early
entrance with limited upfront capital expenditures into markets in
which the Company might not otherwise have power development
opportunities. The integration of power generation plants with the
upstream gas sources in competitive energy markets will also produce
market arbitrage opportunities to sell either gas or electricity
depending upon market conditions at the time. The Company previously
announced two upstream gas projects, one in Western Australia at the
Gingin field in the Perth Basin and one in Poland at the large Pila
Concession.
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. Since 1991, the cost of
production per kilowatt hour ("kWh") at the Company's Coso Projects has
declined from 2.7 cents/kWh to 2.0 cents/kWh. Since 1994, the cost of
production per kWh at the Imperial Valley Projects (as defined herein)
has declined from 5.3 cents/kWh to 2.9 cents/kWh. In each case, the
Company has achieved these efficiencies while maintaining high
reliability and safety in its operation. Through continuing
advancements in drilling technology, reservoir modeling and well
maintenance techniques, the production capacity of new and existing
wells has been improved or maintained and, as a result, the useful
output of the various geothermal resources has been improved or
maintained.
o Continued diversification of revenue base and fuel sources. The
Company believes that it presently has a diversified revenue base,
distributed among its ownership of an operating electricity utility,
its ownership of 1,689 net MW in twenty-one operating projects and its
ownership of producing gas fields. Other than the revenues of
Northern, which are largely derived from its electricity distribution
and supply activities, substantially all of the Company's current
revenues are based on long-term contracts with seven large U.S. utility
companies and the foreign government of the Philippines (sovereign
ratings of Ba1/BB+). The Company intends to seek continued
diversification of its revenue base and fuel sources through
acquisitions and greenfield development.
o Maintenance of prudent financial and risk management
practices. The Company has consistently maintained, and intends in the
future to maintain what it believes to be prudent financial and risk
management practices. A primary objective of the Company is to
structure project financing for development projects which can be rated
investment grade by Moody's Investor Services Inc. and Standard &
Poor's Ratings Services. Its Coso projects are rated Baa2/BBB; its
Salton Sea Funding Corp. is rated Baa3/BBB-; its Northern Electric
subsidiary is rated A3/BBB+, and its CE Electric UK Funding Company
subsidiary's senior notes are rated Baa1/BBB+. The debt ratings
reflected above have been published by Moody's Investors Services, Inc.
and Standard & Poor's Ratings Services, respectively, in respect of
certain senior indebtedness of the respective issuers shown. These
ratings may be changed from time to time by the ratings agencies. The
project financing structures engaged in to date by the Company include
as a fundamental protection for the Company's other assets the
requirement that (with certain minimal exceptions) the funds borrowed
for the purpose of financing a project are to be financed primarily or
entirely under loan agreements and related documents which provide that
the loans are to be repaid solely from the project's revenues and that
the security granted to secure the loan obligation be limited to the
capital stock, assets, contracts and cash flow of the project or its
holding company. Under this type of financing structure, the lenders
cannot seek recourse against the Company or its other subsidiaries or
projects. The Company intends to continue to structure future projects
in a manner which minimizes the exposure of the Company's other assets
through appropriate non-recourse project financings.
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 covered by insurance. The
Company's international investment 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 contracts and regulations;
o Contracts with utilities, governments or other parties
with acceptable creditworthiness which provide for
primarily US$-denominated payments and certain contractual
protections regarding currency convertibility and
transferability;
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 has expanded from a United States market to a
global competitive market as many foreign countries have initiated
restructuring and privatization policies that encourage the development
of independent power generation and independent distribution and supply
of energy. Internationally, large amounts of new electric power
generating capacity are required in developing countries. The movement
toward privatization in some developing countries has created
significant new markets outside the United States. The need for rapid
economic expansion has caused many countries to select private power
development as their only practical alternative and to restructure
their legislative and regulatory systems to facilitate such
development. The Company believes that the significant need for power
in developing markets has created strong local support for private
power projects in many foreign countries and has increased the
availability of attractive long-term power contracts. The Company
intends to take advantage of opportunities in these markets and to
develop, construct and acquire power generation, distribution and
supply and related energy projects meeting its strategic criteria
outside the United States.
In addition, as privatization, deregulation and restructuring
initiatives are enacted in various countries and states, the Company
has identified a number of promising opportunities to acquire power
generation, distribution and supply assets, as well as other energy
related infrastructure assets. These opportunities include bidding
opportunities in connection with privatization initiatives in the
electricity and gas distribution and supply sectors in various
countries, including principally Eastern Europe, South America,
Australia and New Zealand. The Company expects to see more of such
acquisition opportunities in additional markets in the future.
In pursuing its strategy, the Company presently intends to focus
upon development and acquisition opportunities in countries possessing
certain characteristics which meet the Company's investment criteria.
At the present time, the Company is active in the United States, the
Philippines and the United Kingdom and is pursuing development
opportunities in Australia, New Zealand and Poland. 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 capacity that has been placed in
service since 1988. However, as the size of the United States
independent power market increased, available domestic power capacity
and competition in the industry also significantly increased and the
need for new generating capacity has been reduced.
During the last few years, many states began to accelerate the
movement toward more competition in many aspects of the electric power
market, including generation, transmission, distribution and supply.
Extensive federal and state legislative and regulatory reviews are
presently underway in an effort to further such competition. In
particular, the state of California has adopted a bill to restructure
the electric industry by providing for a phased-in competitive power
generation industry, with a power exchange and independent system
operator, and for direct access to generation for all power purchasers
outside the power exchange under certain circumstances. The bill
provides that existing qualifying facility power sales agreements will
be honored. Other states have or are expected to take similar steps
aimed at increasing competition by restructuring the electric industry,
allowing retail competition and deregulating most electric rates. In
addition, recent federal legislation has been proposed which would
repeal PURPA and the Public Utility Holding Company Act of 1935, as
amended, respectively. The Company cannot predict the final form or
timing of the proposed industry restructuring or the result 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.
The United Kingdom
The electricity industry in the United Kingdom has seen the
ongoing privatization of electric supply and distribution since 1990.
The Electricity Act of 1989 established an industry structure that
permitted this phased-in privatization to occur. Since that time, in
England and Wales, electricity is produced by generators, the largest
of which are National Power, PowerGen and British Energy. Electricity
is transmitted through the national grid transmission system by The
National Grid Company plc ("NGC") and distributed to customers by the
twelve regional electric companies ("RECs") in their respective
authorized areas. Most customers currently are supplied with
electricity by their local REC, although there are other suppliers
holding second tier supply licenses, including other generators and
RECs, who can compete to supply larger customers in that REC's
authorized area. Under the current licensing regime, during 1998 it is
expected that all customers, including those who are currently
customers with a maximum demand of not more than 100kW ("Franchise
Supply Customers"), will become free to choose their electricity
supplier.
Virtually all electricity generated in England and Wales is sold
by generators and bought by suppliers through the Pool. A generator
that is a Pool member and also a licensed supplier must nevertheless
sell all the electricity it generates into the Pool, and purchase all
the electricity that it supplies from the Pool. Because Pool prices
fluctuate, generators and suppliers may enter into bilateral
arrangements, such as contracts for differences ("CFDs"), to provide a
degree of protection against such fluctuations.
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 the previous July to December period. The distribution
price control formula also reflects an XD factor which is established
by the Regulator following review and is set at 3% from April 1, 1997.
This formula determines the maximum average price per unit of
electricity distributed (in pence per kilowatt hour) which a REC is
entitled to charge. The distribution price control formula permits RECs
to receive additional revenues due to increased distribution of units
and a predetermined increase in customer numbers. The price control
does not seek to constrain the profits of a REC from year to year. It
is a control on income which operates independently of the REC's costs.
During the lifetime of the price control additional cost savings
therefore contribute directly to profit. The distribution prices
allowable under the current distribution price control formula are
expected to be reviewed by the Regulator at the expiration of the
formula's scheduled five-year duration, effective as of April 1, 2000.
The formula may be further reviewed at other times in the discretion of
the Regulator.
With effect from April 1, 1998, domestic and smaller commercial
customers' prices will be subject to a price cap which requires
reductions of 4.2% (less inflation) compared to the prices prevailing
in July 1997. A further reduction of 3% (less inflation) will be
required on April 1, 1999.
Supply. Subject to minor exceptions, all electricity customers in
the United Kingdom must be supplied by a licensed supplier. Licensed
suppliers purchase electricity and make use of the transmission and
distribution networks to achieve delivery to customers' premises.
There are two types of licensed suppliers: PES (or "first tier")
suppliers and second tier suppliers. PESs are the RECs, Scottish Power
and Hydro-Electric, each supplying in its respective authorized area.
Second tier suppliers include National Power, PowerGen, British Energy,
Scottish Power, Hydro-Electric and other PESs supplying outside their
respective authorized areas. There are also a number of independent
second tier suppliers.
At present, a Franchise Supply Customer can only buy electricity
from the PES authorized to supply the relevant authorized area.
Franchise Supply Customers typically include domestic and small
commercial and small industrial customers. Non-Franchise Supply
Customers with demand over 100kW are not limited to buying electricity
from the local PES and can choose to buy from a second tier supplier.
Such customers are typically larger commercial, agricultural and
industrial electricity users. Second tier suppliers compete with one
another and with the local PES to supply customers in this competitive
(or "non-franchise") sector of the market.
The supply of electricity to all Franchise Supply Customers is
subject to price control until March 31, 1998. The maximum permitted
average charge per unit supplied (in pence per kilowatt hour) is
controlled by a formula whereby certain costs are passed through in
full (the Y term) to customers. The permitted income per unit supplied
in respect of the supply business' own costs and margin increases (or
decreases) each year by RPI--X (the "Supply Price Control Formula")
where X is currently 2%. RPI reflects the average of the 12 month
inflation rates recorded for the previous July to December period. The
X factor is established by the Regulator during the price control
review. The Y term is a pass-through of certain costs which are either
largely outside the control of the REC or have been regulated
elsewhere. It thus covers the REC's electricity purchase costs,
including both direct Pool purchase costs and costs of hedging,
transmission charges made by NGC, distribution charges made by its own
and other REC distribution businesses and other levies which are
attributable to Franchise Supply Customers. Associated with the
deregulation occurring in 1998, a different form of price cap will be
established for some of the current Franchise Supply Customers.
The Pool. The Pool was established at the time of privatization
for bulk trading of electricity in England and Wales between generators
and suppliers. The Pool reflects two principal characteristics of the
physical generation and supply of electricity from a particular
generator to a particular supplier. First, it is not possible to trace
electricity from a particular generator to a particular supplier.
Second, it is not practicable to store electricity in significant
quantities, creating the need for a constant matching of supply and
demand. Subject to certain exceptions, all electricity generated in
England and Wales must be sold and purchased through the Pool. All
licensed generators and suppliers must become and remain signatories to
the Pooling and Settlement Agreement, which governs the constitution
and operation of the Pool and the calculation of payments due to and
from generators and suppliers. The Pool also provides centralized
settlement of accounts and clearing. The Pool does not itself buy or
sell electricity.
Prices for electricity are set by the Pool daily for each one-half
hour of the following day based on the bids of the generators and a
complex set of calculations matching supply and demand and taking
account of system stability, security and other costs. A settlement
system is used to calculate prices and to process metered, operational
and other data and to carry out the other procedures necessary to
calculate the payments due under the Pool trading arrangements. The
settlement system is administered on a day-to-day basis by Energy
Settlements and Information Services, Limited, a subsidiary of NGC, as
settlement system administrator.
The price control regulations which govern the authorized area
supply market permit the pass-through to customers of certain permitted
costs, which include the cost of arrangements such as CFDs to hedge
against Pool price volatility. Generally, CFDs are contracts between
generators and suppliers that have the effect of fixing the price of
electricity for a contracted quantity of electricity over a specific
time period. Differences between the actual price set by the Pool and
the agreed prices give rise to difference payments between the parties
to the particular CFD. At any time, Northern's forecast franchise
supply market demand is substantially hedged through various types of
agreements including CFDs.
The Philippines
According to the 1995 Power Development Program (1995-2005) (the
"PDP") of the National Power Corporation of the Philippines ("NPC"),
industrial growth, a rising standard of living and an expanding power
distribution network have resulted in increased demand for electrical
power in the Philippines by an average of 6% per year since 1987. NPC
has projected that over the next 10 years the need for additional
generating capacity in the Philippines will exceed 14,000 MW. Demand
growth is expected to increase as industrialization continues, living
standards rise and the power distribution network expands. According to
the PDP, for the period 1996 to 2000, projected peak power demand is
estimated to increase by approximately 60%, 64%, and 90% for Luzon, the
Visayas, and Mindanao, respectively. For the country, total projected
peak power is estimated to increase by 3,826 MW or 65% from 1996 to
2000. For the period 2001 to 2005, projected peak power is estimated to
increase by approximately 50%, 43%, and 59% for Luzon, the Visayas, and
Mindanao, respectively. For the country, total projected peak power is
estimated to increase by 5,459 MW or 51% from 2001 to 2005.
The PDP proposes to meet this demand by increasing the
participation of the private sector in power generation to 32% in 2000,
and to 61% in 2005, through direct sales to utilities by independent
power producers and the use of build-own-operate-transfer projects. NPC
also will offer existing power plants to the private sector through
rehabilitate-operate-maintain and rehabilitate-operate-lease
arrangements.
Geothermal power has been identified as a preferred alternative by
the Government of the Philippines due to the domestic availability and
the minimal environmental effects of geothermal power in comparison to
other forms of power production.
The Company's Distribution and Supply Business
Northern Electric Distribution Limited ("Northern Distribution"),
a subsidiary of Northern, receives electricity from the national grid
transmission system and distributes electricity to each customer's
premises using Northern's network of transformers, switchgear and
cables. Substantially all of the customers in Northern's authorized
area are connected to Northern's network and can only be supplied with
electricity through 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, 1997, Northern's electricity distribution network
(excluding service connections to consumers) included approximately
17,000 kilometers of overhead lines and approximately 26,000 kilometers
of underground cables. Substantially all substations are owned in
freehold, and most of the balance are held on leases which will not
expire within 10 years. In addition to the circuits referred to above,
Northern's distribution facilities also include approximately 24,000
transformers and approximately 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. Each of the RECs is currently the
exclusive supplier of electricity in its authorized area to Franchise
Supply Customers. The formula described above controls the income that
the supply business may receive from Franchise Supply Customers and
therefore the profits that can be derived from the supply of
electricity to Franchise Supply Customers. Supplies to other customers
are not regulated since the Director General of Electricity Supply (the
"Regulator") believes that the market in excess of 100kW is
sufficiently competitive not to require this. The current regulations
that permit each of the RECs to be the exclusive supplier in each of
their authorized areas are expected to expire during 1998.
Under the terms of its public electricity supply ("PES") or "first
tier" license, Northern currently holds the right to supply
approximately 1.5 million Franchise Supply Customers within Northern's
authorized area. In addition to competing for non-Franchise Supply
Customers in its authorized area, Northern holds a second tier license
to compete with the RECs and other suppliers to provide electricity to
non-Franchise Supply Customers outside its authorized area. Northern is
one of the largest suppliers in the competitive and open electricity
market in the United Kingdom and supplies customers in all 15 PES areas
in Great Britain and Northern Ireland. Northern supplies substantially
more sites than it had previously supplied prior to the beginning of
open competition in the supply business in the United Kingdom.
Northern Supply also competes to supply gas inside and outside its
authorized area. Over the last six months of 1997, Northern expanded
its supply customer base by 20% by attracting nearly 300,000 new gas
customers in part through the Dual Fuel marketing program.
Northern Utility Services Limited ("Northern Utility") is an
engineering company whose role is to adapt, maintain and restore the
distribution network of Northern Distribution and to sell related
services to third parties. Northern Utility has been able to make
significant cost reductions for Northern during the past year by
working with suppliers in order to improve core processes, close
selected depot locations, increase staff productivity and reduce
material and plant costs. Northern Utility has pioneered techniques
using innovative diagnostic testing equipment which reduces the need
for intrusive maintenance. The equipment can identify some of the
causes of potential systems failures before breakdown and subsequent
loss of supply occurs. Also, the continued development in the use of
trenchless technology has brought both financial and environmental
benefits to Northern and its customers. While Northern Utility's
largest customer is Northern Distribution, it currently sells an
average of approximately 14% of its services to third parties. Northern
Utility is Northern's largest employer.
Northern Electric Retail Limited ("Northern Retail"), a subsidiary
of Northern, sells electrical and gas appliances and provides account
collection and customer services for Northern's other businesses.
Northern Metering Services Limited ("Northern Metering"), a
subsidiary of Northern, provides meter supply, installation,
refurbishment and certification services as well as meter operator and
data collection services. Northern Metering has developed an energy
profiling system which helps businesses reduce costs through the more
efficient use of all fuels, not just electricity.
The Company's Power Generation Project Portfolio
The Company currently has net ownership interests of an aggregate
of (i) 1,689 net MW in 21 projects in operation representing an
aggregate net capacity of 3,510 net MW of electric generating capacity,
(ii) 327 net MW in four projects under construction representing an
aggregate net capacity of 415 net MW of electric generating capacity
and (iii) 945 net MW in eight projects in advanced development stages
with signed power sales agreements or under award representing an
aggregate net capacity of 1,184 net MW of electric generating capacity.
The following tables set out certain information concerning
various Company projects in operation, under construction and in
development pursuant to signed power sales agreements or awarded
mandates.
Power Generation Projects
Projects in Operation
PROJECT(6) FUEL FACILITY NET LOCATION PROJECT CONTRACT CONTRACT POWER
SOURCE NET OWNERSHIP COMMERCIAL EXPIRATION TYPE PURCHASE
CAPACITY INTEREST OPERATION
(IN MW) (IN MW) DATE(9)
(1)(2)(3)
United States
Navy I Geo 88 41 China 8/1987 8/2011 SO4 Edison
Lake,CA
BLM Geo 88 42 China 3/1989 3/2019 SO4 Edison
Lake,CA
Navy II Geo 88 44 China 1/1990 1/2010 SO4 Edison
Lake,CA
Vulcan Geo 34 34 Imperial 2/1986 2/2016 SO4 Edison
Valley,CA
Hoch (Del Geo 38 38 Imperial 1/1989 12/2018 SO4 Edison
Ranch) Valley,CA
Elmore Geo 38 38 Imperial 1/1989 12/2018 SO4 Edison
Valley,CA
Leathers Geo 38 38 Imperial 1/1990 12/2019 SO4 Edison
Valley,CA
Salton Geo 10 10 Imperial 7/1987 6/2017 Negot. Edison
Sea I Valley,CA
Salton Geo 20 20 Imperial 4/1990 4/2020 SO4 Edison
Sea II Valley,CA
Salton Geo 50 50 Imperial 2/1989 2/2019 SO4 Edison
Sea III Valley,CA
Salton Geo 40 40 Imperial 6/1996 9/2017 Negot. Edison
Sea IV Valley,CA
Saranac Gas 240 180 Plattsburg 6/1994 6/2009 Negot. NYSEG
NY
Power Gas 200 200 Big Spring,6/1988 9/2003 Negot. TUEC
Resources TX
NorCon Gas 80 64 North East,12/1992 12/2017 Negot. NIMO
PA
Yuma Gas 50 50 Yuma,AZ 5/1994 5/2024 Negot. SDG&E
Roosevelt Geo 23 17 Milford,UT 5/1984 1/2021 Gathered UP&L
Hot Springs (5) Steam
Desert Geo 10 10 Sparks,NV 1985 Not Negot. SPPC
Peak Fixed
United Kingdom
Teesside Gas 1,875 289 Wilton, 1993 2008 Negot. Various
Power England
Limited
Philippines
Upper Geo 119 119 Leyte, 1996 CO+10 Build, PNOC-EDC
Mahiao Philippines Own (GOP)(8)
(7) Transfer
Malitbog Geo 216 216 Leyte, 1996-97 CO+10 Build, PNOC-EDC
(7) Philippines Own (GOP)(8)
Transfer
Mahanagdong Geo 165 149 Leyte, 1997 CO+10 Build, PNOC-EDC
(7) Philippines Own (GOP)(8)
Transfer
Total in 3,510 1,689
Operation
(1)Excludes royalty income received by Magma from the Mammoth and East Mesa
plants.
(2)Actual MW may vary depending on operating and reservoir conditions and
plant design. Facility Net Capacity (in MW) for projects in operation
represents gross electric output of the facility less the parasitic load.
Parasitic load is electrical output used by the facility and not made
available for sale to utilities or other outside purchasers. Net MW owned
indicates current ownership, but, in some cases, does not reflect the
current allocation of partnership distributions.
(3)With respect to the Vulcan, Hoch (Del Ranch), Elmore, Leathers, Salton
Sea I, Salton Sea II, Salton Sea III and Salton Sea IV Projects, this
represents nominal nameplate.
(4)Southern California Edison Company ("Edison"); San Diego Gas & Electric
Company ("SDG&E"); Utah Power & Light Company ("UP&L"); Sierra Pacific
Power Company ("SPPC") ; New York State Electric & Gas Corporation
("NYSEG"); Texas Utilities Electric Company ("TUEC"); and Niagara Mohawk
Power Corporation ("NIMO"); PNOC-Energy Development Corporation ("PNOC-
EDC"); Government of Philippines ("GOP").
(5)Represents the electrical equivalent of delivered steam.
(6)The Company operates all such projects other than Teesside Power
Limited.
(7)Construction of these facilities has been completed and, accordingly,
these facilities have been "deemed complete" by PNOC-EDC and are currently
receiving the full capacity payments under the "take or pay" provisions of
their contracts with PNOC-EDC, pending NPC making available to these
projects a full capacity transmission line.
(8)Government of Philippines undertaking supports PNOC-EDC's obligations.
(9)Commercial Operation ("CO") plus number of years.
Projects in Construction
PROJECT FUEL FACILITY NET LOCATION CONTRACT CONTRACT POWER POLITICAL
SOURCE NET OWNER EXPIRATION TYPE PURCHASER RISK
CAPACITY INTEREST (1) (2) INSURANCE
(IN MW) (IN MW) AND
(5) PRIMARILY
US$
CONTRACT
United Kingdom
Viking Gas 50 25 Seal CO+10 Negot Northern No
Sands on
Teesside,
England
Philippines
Casecnan Hydro 150 105 Luzon,the CO+20 Build, NIA Yes
(4) Philippines Own (GOP)(3)
Transfer
Indonesia
Dieng Geo 55 52 Central CO+30 Build, PLN Yes
Unit Java, Own, (GOI)
I(6) Indonesia Transfer
Dieng Geo 80 75 Central CO+30 Build, PLN Yes
Unit Java, Own, (GOI)
II(6) Indonesia Transfer
Patuha Geo 80 70 Western CO+30 Build, PLN Yes
Unit Java, Own, (GOI)
I(6) Indonesia Transfer
Total in 415 327
Construction
(1)Commercial Operation ("CO") plus number of years.
(2)Government of the Philippines ("GOP"); P.T. PLN (Persero) ("PLN");
Government of Indonesia ("GOI"); and Philippine National Irrigation
Administration ("NIA"), Northern Electric plc ("Northern").
(3)Government of the Philippines undertaking supports NIA's obligations.
(4)NIA also purchases water from this facility.
(5)Actual MW may vary depending on operating and reservoir conditions and
final plant design. Significant contingencies exist in respect of awards,
including without limitation, the need to obtain financing, permits and
licenses, and the completion of construction.
(6)See discussion of uncertainties caused by recent actions of Government
of Indonesia below.
Projects with Signed Power Sales Contracts or Awarded Development
Rights
PROJECT(S) FUEL FACILITY NET LOCATION CONTRACT CONTRACT POWER
SOURCE NET OWNERSHIP EXPIRATION TYPE PURCHASER
CAPACITY INTEREST (2) (3)
(IN MW) (IN MW)
(1)
United States
Salton Sea Geo 49 49 Imperial TBD TBD TBD
Sea Mineral Valley, CA
Extraction
Telephone Geo 30 30 Siskiyou CO+20 Negot. BPA
Flat(7) County, CA
United Kingdom
Exeter Gas 50 25 England CO+10 Negot. Northern
Philippines
Alto Peak Geo 70 70 Leyte,the CO+10 Build, PNOC-EDC
Philippines Own, (GOP)(4)
Transfer
Indonesia
Dieng Geo 265 249 Central Java, CO+30 Build, PLN
Phase II Indonesia Own, (GOI)
(6) Transfer
Patuha Geo 320 282 Western Java, CO+30 Build, PLN
Phase II Indonesia Own, (GOI)
Transfer
Bali(6) Geo 400 240 Bali, CO+30 Build, PLN
Indonesia Own, (GOI)
Transfer
Total 1,184 945
Contracted/Awarded
(1)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.
(2)Commercial Operation ("CO") plus number of years.
(3)PNOC-Energy Development Corporation ("PNOC-EDC"), Government of the
Philippines ("GOP"); P.T. PLN (Persero)("PLN"); Government of Indonesia
("GOI"); Northern Electric plc ("Northern"); Bonneville Power Authority
("BPA")
(4)Government of the Philippines undertaking supports PNOC-EDC's
obligations.
(5)Significant contingencies exist in respect of awards, including without
limitation, the need to obtain financing, permits and licenses, and the
completion of construction.
(6)See discussion of uncertainties caused by recent actions by the
Government of Indonesia below.
(7)The Newberry project has been moved to Telephone Flat to take advantage
of better reservoir conditions at the latter location. A settlement
agreement has been executed with BPA to recognize the move, subject to
completion of certain activities including an environmental impact
statement.
PROJECTS IN OPERATION
United States Operations
The Coso Project
In 1979, the Company entered into a 30-year contract (the "Navy
Contract") with the United States Department of the Navy (the "Navy")
to develop geothermal power facilities located on approximately 5,000
acres of the Naval Air Weapons Station at China Lake, California (150
miles northeast of Los Angeles). In 1985, the Company entered into a
30-year lease (the "BLM Lease") with the United States Bureau of Land
Management ("BLM") for approximately 19,000 acres of land adjacent to
the land covered by the Navy Contract. The Navy Contract and the BLM
Lease provide for certain royalty payments as a percentage of gross
revenue and certain other formulas. The Company formed three joint
ventures (the "Coso Joint Ventures") with one primary joint venture
partner to develop and construct the three facilities which comprise
the Navy I project (the "Navy I Project"), the BLM project (the "BLM
Project") and the Navy II project (the "Navy II Project") (collectively
the "Coso Project").
The Coso Joint Ventures are as follows: (i) Coso Finance
Partners, which owns the Navy I Project (the "Navy I Partnership"),
(ii) Coso Energy Developers, which owns the BLM Project (the "BLM
Partnership") and (iii) Coso Power Developers, which owns the Navy II
Project (the "Navy II Partnership"). The Company holds ownership
interests of 46.4%, 48% and 50% in the Navy I Partnership, the BLM
Partnership, and the Navy II Partnership, respectively. The Company
consolidates its respective share of the operating results of the Coso
Joint Ventures into its financial statements. Each of the Coso Joint
Ventures is managed by a management committee which consists of two
representatives of the Company and two representatives of the Company's
partners. The Company is the managing partner of each of the Coso
Partnerships and operates the Coso Project, for which it receives fees
from the Coso Joint Ventures.
The Coso Project sells all electricity generated by the respective
plants pursuant to three long-term SO4 Agreements between the Navy I
Partnership, the BLM Partnership, and the Navy II Partnership,
respectively, and Edison. These SO4 Agreements provide for capacity
payments, capacity bonus payments and energy payments. Edison makes
fixed annual capacity payments to the Coso Joint Ventures and, to the
extent that capacity factors exceed certain benchmarks, is required to
make capacity bonus payments. The price for capacity and capacity
bonus payments is fixed for the life of the SO4 Agreements. Energy is
sold at increasing fixed rates for the first ten years after firm
operation and thereafter at Edison's Avoided Cost of Energy. The fixed
price periods of the SO4 Agreements extend until at least August 1997,
March 1999 and January 2000 for each of the units operated by the Navy
I, BLM and Navy II Partnerships, respectively.
For the year ended December 31, 1997 and 1996 Edison's average
Avoided Cost of Energy was 3.3 cents and 2.5 cents, respectively, per
kWh which is substantially below the contract energy prices earned for
the year ended December 31, 1997. Estimates of Edison's future Avoided
Cost of Energy vary substantially from year to year. The Company
cannot predict the likely level of Avoided Cost of Energy prices under
the SO4 Agreements and the modified SO4 Agreements at the expiration of
the scheduled payment periods. The revenues generated by each of the
projects operating under SO4 Agreements could decline significantly
after the expiration of the respective scheduled payment periods.
On June 9, 1997, Edison filed a complaint alleging breach of the
power purchase agreements ("SO4 Agreements") between Edison and the
Coso Joint Ventures as a result of alleged improper venting of certain
noncondensible gases at the Coso geothermal energy project. In the
complaint, Edison seeks unspecified damages, including the refund of
certain amounts previously paid under the SO4 Agreements, and
termination of the SO4 Agreements. In September 1997, the Coso Joint
Ventures and the Company filed a cross-complaint against Edison and its
affiliates, The Mission Group and Mission Power Engineering Company
alleging, among other things, that Edison's lawsuit violates the 1993
settlement agreement which settled certain litigation arising from the
construction of certain units at the Coso geothermal project by Edison
affiliates. In addition, the Coso Joint Ventures filed a separate
complaint against Edison alleging breach of the SO4 Agreements, unfair
business practices, slander and various other tort and contract claims.
The actions were effectively consolidated in December 1997. As a
result of certain procedural actions by the parties and a November
court order, Edison filed an amended complaint on December 16, 1997 and
the Coso Joint Ventures amended their cross-complaint. The litigation
is in its early procedural stages and the pleadings have not been
settled. The Coso Joint Ventures believe that their claims and
defenses are meritorious and that they will prevail if the matter is
ultimately heard on its merits. The Coso Joint Ventures intend to
vigorously defend this action and prosecute all available counterclaims
against Edison.
Navy I Project. The geothermal resource for the Navy I Project
currently is produced from approximately 35 wells. The Navy I Project
consists of three turbine generators, each with approximately 32 gross
MW of electrical generating capacity.
BLM Project. The BLM Project's geothermal resource currently is
produced from approximately 24 wells. The BLM Project consists of
three turbine generators. Two of these turbine generators are located
at the BLM East site in a dual flash system, and one is located at the
BLM West site in a single flash system, each with an electrical
generating capacity of 32 gross MW.
Navy II Project. The geothermal resource for the Navy II Project
currently is produced from approximately 23 wells. The Navy II Project
consists of three individual turbine generators, each with
approximately 32 gross MW of electrical generating capacity.
Imperial Valley Project
The Company currently operates eight geothermal plants in the
Imperial Valley in California (the "Imperial Valley Project"). Four of
these Imperial Valley Project plants (the "Partnership Projects") were
developed by Magma which originally owned a 50% interest. On April 17,
1996, the Company completed the Partnership Interest Acquisition
pursuant to which the Company acquired the remaining 50% interests in
each of the Partnership Projects for $70 million. The Partnership
Projects consist of the Vulcan, Hoch (Del Ranch), Elmore and Leathers
projects (the "Vulcan Project," the "Hoch (Del Ranch) Project," the
"Elmore Project" and the "Leathers Project," respectively).
The remaining four operating Imperial Valley Project plants (the
"Salton Sea Projects") are wholly owned by subsidiaries of Magma.
Three of these plants were purchased on March 31, 1993 from Union Oil
Company of California. These geothermal power plants consist of the
Salton Sea I project (the "Salton Sea I Project"), the Salton Sea II
project (the "Salton Sea II Project") and the Salton Sea III project
(the "Salton Sea III Project"). The fourth plant, the Salton Sea IV
project (the "Salton Sea IV Project"), commenced commercial operations
in 1996.
Vulcan. The Vulcan Project sells electricity to Edison under a 30-
year SO4 Agreement that commenced on February 10, 1986. The Vulcan
Project has a contract capacity and contract nameplate of 29.5 MW and
34 MW, respectively. Under the SO4 Agreement, Edison is obligated to
pay the Vulcan Project a capacity payment, a capacity bonus payment and
an energy payment.
The price for contract capacity payments is fixed for the life of
such SO4 Agreement. The as-available capacity price is based on a
payment schedule as approved by the CPUC from time to time. The
contract energy payment increased each year for the first ten years,
which period expired on February 9, 1996. Thereafter, the energy
payments are based on Edison's Avoided Cost of Energy.
Hoch (Del Ranch). The Hoch (Del Ranch) Project sells electricity
to Edison under a 30-year SO4 Agreement that commenced on January 2,
1989. The contract capacity and contract nameplate are 34 MW and 38
MW, respectively. The provisions of such SO4 Agreement are
substantially the same as the SO4 Agreement with respect to the Vulcan
Project.
The price for contract capacity payments is fixed for the life of
the SO4 Agreement. The fixed price period for energy payments per kWh
expires on January 1, 1999. After January 1, 1999, the energy payments
will be based on Edison's Avoided Cost.
Elmore. The Elmore Project sells electricity to Edison under a 30-
year SO4 Agreement that commenced on January 1, 1989. The contract
capacity and contract nameplate are 34 MW and 38 MW, respectively. The
provisions of such SO4 Agreement are substantially the same as the SO4
Agreement with respect to the Vulcan Project.
The price for contract capacity payments is fixed for the life of
SO4 Agreement. The fixed price period for energy payments per kWh
expires on December 31, 1998. After December 31, 1998, the energy
payments will be based on Edison's Avoided Cost of Energy.
Leathers. The Leathers Project sells electricity to Edison
pursuant to a 30-year SO4 Agreement that commenced on January 1, 1990.
The contract capacity and contract nameplate are 34 MW and 38 MW,
respectively. The provisions of such SO4 Agreement are substantially
the same as the SO4 Agreement with respect to the Vulcan Project.
The price for contract capacity payments is fixed for the life of
SO4 Agreement which expires on December 31, 1999. Thereafter, the
energy payments will be based on Edison's Avoided Cost of Energy.
Salton Sea I Project. The Salton Sea I Project sells electricity
to Edison pursuant to a 30-year negotiated power purchase agreement, as
amended (the "Salton Sea I PPA"), which provides capacity and energy
payments. The contract capacity and contract nameplate are each 10 MW.
The capacity payment is based on the firm capacity price which is
currently $132.58kW-year. The contract capacity payment adjusts
quarterly based on a basket of energy indices for the term of the
Salton Sea I PPA. The energy payment is calculated using a Base Price
(defined as the initial value of the energy payment (4.701 center 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
1997. 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 expires on February 12, 1999, are
levelized at a time period weighted average of 9.8 cents per kWh.
Thereafter, the monthly energy payments will be Edison's Avoided Cost
of Energy.
The Salton Sea IV Project sells electricity to Edison pursuant to
a modified SO4 agreement which provides for contract capacity payments
on 34 MW of capacity at two different rates based on the respective
contract capacities deemed attributable to the original Salton Sea PPA
option (20 MW) and to the original Fish Lake PPA (14 MW). The capacity
payment price for the 20 MW portion adjusts quarterly based upon
specified indices and the capacity payment price for the 14 MW portion
is a fixed levelized rate. The energy payment (for deliveries up to a
rate of 39.6 MW) is at a fixed price for 55.6% of the total energy
delivered by Salton Sea IV and is based on an energy payment schedule
for 44.4% of the total energy delivered by Salton Sea IV. The contract
has a 30-year term but Edison is not required to purchase the 20 MW of
capacity and energy originally attributable to the Salton Sea I PPA
option after September 30, 2017, the original termination date of the
Salton Sea I PPA.
U.S. Gas Projects
Yuma Project. The Yuma Project is a 50 net MW natural gas-fired
cogeneration project in Yuma, Arizona providing 50 MW of electricity to
San Diego Gas & Electric Company ("SDG&E") under an existing 30-year
power purchase contract. The energy is sold at SDG&E's Avoided Cost of
Energy and the capacity is sold to SDG&E at a fixed price for the life
of the power purchase contract. The power is wheeled to SDG&E over
transmission lines constructed and owned by Arizona Public Service
Company ("APS"). An agreement for interconnection and a firm
transmission service agreement have been executed between APS and the
Yuma Project entity and have been accepted for filing by the FERC.
The Yuma Project commenced commercial operation in May 1994. The
project entity has executed steam sales contracts with an adjacent
industrial entity to act as its thermal host. Since the industrial
entity has the right under its agreement to terminate the agreement
upon one year's notice if a change in its technology eliminates its
need for steam, and in any case to terminate the agreement at any time
upon three years notice, there can be no assurance that the Yuma
Project will maintain its status as a QF. However, if the industrial
entity terminates the agreement, the Company anticipates that it will
be able to locate an alternative thermal host in order to maintain its
status as a QF. A natural gas supply and transportation agreement has
been executed with Southwest Gas Corporation, terminable under certain
circumstances by the Company and Southwest Gas Corporation. The Yuma
Project is unleveraged other than intercompany debt.
Saranac Project. Saranac is a 240 net MW natural gas-fired
cogeneration facility located in Plattsburgh, New York, which began
commercial operation in June 1994. Saranac has entered into a 15-year
power purchase agreement (the "Saranac PPA") with NYSEG. Saranac is a
QF and has entered into 15-year steam purchase agreements (the "Saranac
Steam Purchase Agreements") with Georgia-Pacific Corporation and
Tenneco Packaging, Inc. Saranac has a 15-year natural gas supply
contract (the "Saranac Gas Supply Agreement") with Shell Canada Limited
("Shell Canada") to supply 100% of Saranac's fuel requirements. Shell
Canada is responsible for production and delivery of natural gas to the
U.S.-Canadian border; the gas is then transported by the North Country
Gas Pipeline Corporation ("NCGP") the remaining 22 miles to the plant.
NCGP is a wholly-owned subsidiary of Saranac Power Partners, L.P. (the
"Saranac Partnership"), which also owns Saranac. NCGP also transports
gas for NYSEG and Georgia-Pacific.
Each of the Saranac PPA, the Saranac Steam Purchase Agreements and
the Saranac Gas Supply Agreement contains rates that are fixed for the
respective contract terms. Revenues escalate at a higher rate than
fuel costs. The Saranac Partnership is owned by subsidiaries of the
Company, Tomen Corporation ("Tomen"), and General Electric Capital
Corporation.
On February 14, 1995, NYSEG filed with the FERC a Petition for a
Declaratory Order, Complaint, and Request for Modification of Rates in
Power Purchase Agreements Imposed Pursuant to the Public Utility
Regulatory Policies Act of 1978 ("Petition") seeking FERC (i) to
declare that the rates NYSEG pays under the Saranac PPA, which was
approved by the New York Public Service Commission (the "PSC"), were in
excess of the level permitted under PURPA and (ii) to authorize the PSC
to reform the Saranac PPA. On March 14, 1995, the Saranac Partnership
intervened in opposition to the Petition asserting, Inter alia, that
the Saranac PPA fully complied with PURPA, that NYSEG's action was
untimely and that the FERC lacked authority to modify the Saranac PPA.
On March 15, 1995, the Company intervened also in opposition to the
Petition and asserted similar arguments. On April 12, 1995, the FERC
by a unanimous (5-0) decision issued an order denying the various forms
of relief requested by NYSEG and finding that the rates required under
the Saranac PPA were consistent with PURPA and the FERC's regulations.
On May 11, 1995, NYSEG requested rehearing of the order and, by order
issued July 19, 1995, the FERC unanimously (5-0) denied NYSEG's
request. On June 14, 1995, NYSEG petitioned the United States Court of
Appeals for the District of Columbia Circuit (the "Court of Appeals")
for review of FERC's April 12, 1995 order. FERC moved to dismiss
NYSEG's petition for review on July 28, 1995. On October 30, 1996, all
parties filed final briefs and the Court of Appeals heard oral
arguments on December 2, 1996. On July 11, 1997, the Court of Appeals
dismissed NYSEG's appeal from FERC's denial of the petition on
jurisdictional grounds.
On August 7, 1997, NYSEG filed a complaint in the U.S. District
Court for the Northern District of New York against the FERC, the PSC
(and the Chairman, Deputy Chairman and the Commissioners of the PSC as
individuals in their official capacity), the Saranac Partnership and
Lockport Energy Associates, L.P. ("Lockport") concerning the power
purchase agreements that NYSEG entered into with Saranac Partners and
Lockport.
NYSEG's suit asserts that the PSC and the FERC improperly
implemented PURPA in authorizing the pricing terms that NYSEG, the
Saranac Partnership and Lockport agreed to in those contracts. The
action raises similar legal arguments to those rejected by the FERC in
its April and July 1995 orders. NYSEG in addition asks for retroactive
reformation of the contracts as of the date of commercial operation and
seeks a refund of $281 million from the Saranac Partnership. Saranac
and other parties have filed motions to dismiss and oral arguments on
those motions were heard on March 2, 1998. Saranac believes that
NYSEG's claims are without merit for the same reasons described in the
FERC's orders.
Power Resources Project. Power Resources is a 200 net MW natural
gas-fired cogeneration project located near Big Spring, Texas, which
has a 15-year power purchase agreement (the "Power Resources PPA") with
Texas Utilities Electric Company. Power Resources began commercial
operation in June 1988. Power Resources is a QF and has entered into a
15-year steam purchase agreement (the "Power Resources Steam Purchase
Agreement") with Fina Oil and Chemical Company ("Fina"), a subsidiary
of Petrofina S.A. of Belgium.
Power Resources has entered into an agreement (the "FSGC Gas
Supply Agreement") with Falcon Seaboard Gas Company ("FSGC") for Power
Resources' fuel requirements through December 2003. FSGC has fulfilled
its commitments to Power Resources, Inc. ("PRI") to date using a
combination of spot purchases plus short-term contracts. In June 1995,
FSGC and Louis Dreyfus Natural Gas Corp. ("Dreyfus") executed an eight-
year natural gas supply agreement (the "FSGC-Dreyfus Gas Supply
Agreement"), with which FSGC will fulfill its supply commitment to PRI
from October 1995 to the end of the term of the Power Resources PPA.
Accordingly, through the FSGC-Dreyfus Gas Supply Agreement, all gas
requirements have been contracted for through the end of the Power
Resources PPA.
Each of the Power Resources PPA, the Power Resources Steam
Purchase Agreement and the FSGC Gas Supply Agreement contains rates
that are fixed for the respective contract terms. Revenues escalate at
a higher rate than fuel costs.
NorCon Project. NorCon is an 80 net MW natural gas-fired
cogeneration facility located in North East, Pennsylvania which began
commercial operation in December 1992. NorCon has a 25-year power
purchase agreement (the "NorCon PPA") with Niagara Mohawk Power
Corporation ("NIMO"). NorCon is a QF and has entered into a 20-year
steam purchase agreement (the "NorCon Thermal Energy Agreement") with
Welch Foods Inc., a Cooperative ("Welch Foods").
NorCon has a 15-year natural gas supply contract (the "NorCon Gas
Purchase Agreement") with Louis Dreyfus Gas Marketing Corp. to supply
100% of NorCon's fuel requirements. A twenty-year natural gas
transportation agreement has been entered into with National Fuel Gas
Supply Corporation ("National Fuel") to provide transportation to
NorCon. Transportation costs are deducted from payments made pursuant
to the NorCon Gas Purchase Agreement. The NorCon PPA has rates that
are subject to a specified floor amount. The NorCon Thermal Energy
Agreement contains rates that escalate at an inflation-based index, and
the NorCon Gas Purchase Agreement's rates are fixed for the contract
term.
NorCon Power Partners, L.P. ("the "NorCon Partnership"), which
owns NorCon, is owned by subsidiaries of the Company and Tomen.
The NorCon project has had a number of on-going contractual
disputes with NIMO which are unresolved and in August 1996 NIMO
proposed a buyout of the NorCon PPA as part of a generic restructuring
by NIMO of all of its QF contracts in an effort to restructure NIMO's
purchased power obligations to meet the challenge of industry
deregulation and avoid what NIMO alleges as the risk of a possible NIMO
insolvency. The Company believes that any contractual restructuring or
even a NIMO insolvency would not have a material adverse effect on its
consolidated financial results of operations.
Other U.S. Geothermal Operations
Roosevelt Hot Springs. 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. The Company is the owner, and currently the
operator, of a 10 net MW geothermal plant at Sparks, Nevada. The
Desert Peak Project has been selling electricity to Sierra Pacific
Power Company ("SPPC") on a spot market basis since its power sales
contract with SPPC expired December 31, 1995. The Company recently
executed an agreement pursuant to which the Desert Peak Project will be
leased to a third party power producer and the Company will receive
rental payments.
Royalty Interests
Mammoth. Magma receives royalty revenues from a 10 net MW and a
12 net MW contract nameplate geothermal power plant (the "First Mammoth
Plant" and the "Second Mammoth Plant," respectively, and referred to
herein, collectively, as the "Mammoth Plants") at Mammoth Lakes,
California. Electricity from the Mammoth Plants is sold to Edison
under two long-term power purchase agreements. The First Mammoth Plant
and the Second Mammoth Plant began commercial operation in 1985 and
1991, respectively. Magma leases both property and geothermal
resources to support the Mammoth Plants in return for certain base
royalty and bonus royalty payments. For the First Mammoth Plant and
the Second Mammoth Plant, the base royalty is 12.5% and 12%,
respectively, of gross electricity sales revenues. The bonus royalty
for the Mammoth Plants is 50% of the excess of annual gross electricity
sales revenues over an annual revenue standard based on the Mammoth
Plants operating at 85% of contract capacity.
East Mesa. Magma also receives royalty revenues from a 37 net MW
contract nameplate geothermal power plant (with two units) at East Mesa
in Imperial Valley, California (the "East Mesa Project"). Electricity
from the plant has been sold to Edison pursuant to two SO4 Agreements
formerly held by Magma. The East Mesa Project participants have
executed an agreement with Edison to terminate the SO4 Agreement.
Pursuant to a Settlement Agreement, Magma consented to such
termination.
United Kingdom Operations and Construction
In the United Kingdom, a Northern subsidiary, Northern Electric
Generation Limited ("Northern Generation"), focuses on electricity
generation, primarily through its ownership in Teesside (described
herein). Northern Generation also operates a 5 MW diesel power
generating plant located in Northallerton, England in which the Company
has a 3 MW net ownership interest.
Teesside. Teesside Power Limited ("Teesside") owns and operates
an 1,875 net MW combined cycle gas-fired power plant at Wilton.
Northern owns a 15.4% interest in Teesside, but does not operate the
plant. Northern purchases 400 MW of electricity from Teesside under a
long-term power purchase agreement.
Viking. Viking Power Limited ("Viking") is a company owned 50% by
Northern and 50% by Rolls-Royce Power Ventures. Viking is a project to
construct a 50 net MW natural gas-fired power plant at Seal Sands on
Teesside. The project will utilize an aero-derivative Rolls-Royce
Trent Engine and it will be embedded on the Northern distribution
network. Construction has commenced on the plant and the project is
being managed by Northern and will be operated by Northern upon
commercial operation.
The Philippines Operations and Construction
Upper Mahiao. The Upper Mahiao facility was "deemed complete" by
PNOC-EDC as of June 17, 1996, meaning that construction of the facility
was completed on time but the required full capacity transmission line
was not completed and provided to CE Cebu Geothermal Power Company,
Inc. ("CE Cebu"), a Philippine corporation that is 100% indirectly
owned by the Company. During deemed completion, PNOC-EDC is required
to pay all capacity fees under the take or pay provisions of the
contract. PNOC-EDC is paying such capacity fees on a timely basis.
Effective September 13, 1996, the "deemed completion" was modified, to
allow delivery of up to 40 MW of power through a temporary transmission
facility. This amendment allows for payment to CE Cebu of fees for
energy delivered in addition to continuing the payment for the full
capacity fee.
A consortium of international banks provided the construction
loans, supported by political risk insurance from the Ex-Im Bank. The
construction loan is expected to be converted to a term loan promptly
after NPC completes the full capacity transmission line. The
transmission line is currently being tested and testing is expected to
be completed in the second quarter of 1998.
Under the terms of an energy conversion agreement, executed on
September 6, 1993 (the "Upper Mahiao ECA"), CE Cebu will own and
operate the Upper Mahiao Project during the ten-year cooperation
period, after which ownership will be transferred to PNOC-EDC at no
cost.
The Upper Mahiao Project is located on land provided by PNOC-EDC
at no cost. It takes geothermal steam and fluid, also provided by PNOC-
EDC at no cost, and converts its thermal energy into electrical energy
sold to PNOC-EDC on a "take-or-pay" basis. Specifically, PNOC-EDC is
obligated to pay for 100% of the electric capacity that is nominated
each year by CE Cebu, irrespective of whether PNOC-EDC is willing or
able to accept delivery of such capacity. PNOC-EDC pays to CE Cebu a
fee (the "Capacity Fee") based on the plant capacity nominated to PNOC-
EDC in any year (which, at the plant's design capacity, is
approximately 95% of total contract revenues) and a fee (the "Energy
Fee") based on the electricity actually delivered to PNOC-EDC
(approximately 5% of total contract revenues). Payments under the
Upper Mahiao ECA are denominated in U.S. dollars, or computed in U.S.
dollars and paid in Philippine pesos at the then-current exchange rate,
except for the Energy Fee. Significant portions of the Capacity Fee
and Energy Fee are indexed to U.S. and Philippine inflation rates,
respectively. PNOC-EDC's payment requirements, and its other
obligations under the Upper Mahiao ECA, are supported by the Government
of the Philippines through a performance undertaking.
The payment of the Capacity Fee is not excused if PNOC-EDC fails
to deliver or remove the steam or fluids or fails to provide the
transmission facilities, even if its failure was caused by a force
majeure event. In addition, PNOC-EDC must continue to make Capacity
Fee payments if there is a force majeure event (e.g., war,
nationalization, etc.) that affects the operation of the Upper Mahiao
Project and that is within the reasonable control of PNOC-EDC or the
Government of the Philippines or any agency or authority thereof.
PNOC-EDC is obligated to purchase CE Cebu's interest in the
facility under certain circumstances, including (i) extended outages
resulting from the failure of PNOC-EDC to provide the required
geothermal fluid, (ii) certain material changes in policies or laws
which adversely affect CE Cebu's interest in the project, (iii)
transmission failure, (iv) failure of PNOC-EDC to make timely payments
of amounts due under the Upper Mahiao ECA, (v) privatization of PNOC-
EDC or NPC, and (vi) certain other events. The price will be the net
present value (at a discount rate based on the last published
Commercial Interest Reference Rate of the Organization for Economic
Cooperation and Development) of the total remaining amount of Capacity
Fees over the remaining term of the Upper Mahiao ECA.
Mahanagdong. The Mahanagdong Project is a 165 net MW geothermal
power project owned and operated by CE Luzon Geothermal Power Company,
Inc. ("CE Luzon"), a Philippine corporation that is currently 100%
indirectly owned by the Company. Up to a 10% financial interest in CE
Luzon may be purchased at completion by another industrial company at
the option of such company. The Mahanagdong Project was "deemed
complete" by PNOC-EDC as of July 25, 1997. The Mahanagdong Project
will sell 100% of its capacity on a similar basis as described above
for the Upper Mahiao Project to PNOC-EDC, which will in turn sell the
power to NPC for distribution to the island of Luzon.
The project financing construction and term loan is being provided
by OPIC, Ex-Im Bank and a consortium of international banks. Political
risk insurance from Ex-Im Bank has been obtained for the commercial
lenders. The construction loan is expected to be converted to a term
loan promptly after NPC completes the full capacity transmission line
which is currently expected to be in the second quarter of 1998.
The terms of an energy conversion agreement, executed on September
18, 1993 (the "Mahanagdong ECA"), are substantially similar to those of
the Upper Mahiao ECA. The Mahanagdong ECA provides for an
approximately three-year construction period and a ten-year cooperation
period. At the end of the cooperation period, the facility will be
transferred to PNOC-EDC at no cost. All of PNOC-EDC's obligations
under the Mahanagdong ECA are supported by the Government of the
Philippines through a performance undertaking. The capacity fees are
expected to be approximately 97% of total revenues at the design
capacity levels and the energy fees are expected to be approximately 3%
of such total revenues.
Malitbog. 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 "deemed
complete" by PNOC-EDC as of July 25, 1996 (for Unit I) and July 25,
1997 (for Units II and III). During deemed completion, PNOC-EDC is
required to pay, and has been paying, all capacity fees under the take
or pay provisions of the contract. VGPC is selling 100% of its
capacity on substantially the same basis as described above for the
Upper Mahiao Project to PNOC-EDC, which will in turn sell the power to
NPC.
A consortium of international banks and OPIC have provided the
construction and term loan facilities. The construction loan is
expected to be converted to a term loan promptly after NPC completes
the full capacity transmission line. The transmission line is
currently being tested and testing is expected to be completed in the
second quarter of 1998.
The Malitbog Project is located on land provided by PNOC-EDC at no
cost. The electrical energy produced by the facility will be sold to
PNOC-EDC on a take-or-pay basis. Specifically, PNOC-EDC is obligated
to make payments (the "Capacity Payments") to VGPC based upon the
available capacity of the Malitbog Project. The Capacity Payments
equal approximately 100% of total revenues. The Capacity Payments will
be payable so long as the Malitbog Project is available to produce
electricity, even if the Malitbog Project is not operating due to
scheduled maintenance, because PNOC-EDC fails to supply steam to the
Malitbog Project as required or because NPC is unable (or unwilling) to
accept delivery of electricity from the Malitbog Project. In addition,
PNOC-EDC must continue to make the Capacity Payments if there is a
force majeure event (e.g., war, nationalization, etc.) that affects the
operation of the Malitbog Project and that is within the reasonable
control of PNOC-EDC or the Government of the Philippines or any agency
or authority thereof. A substantial majority of the Capacity Payments
are required to be made by PNOC-EDC in dollars. The portion of
Capacity Payments payable to PNOC-EDC in pesos is expected to vary over
the term of the Malitbog ECA from 10% of VGPC's revenues in the early
years of the Cooperation Period (as defined below) to 23% of VGPC's
revenues at the end of the Cooperation Period. Payments made in pesos
will generally be made to a peso-dominated account and will be used to
pay peso-denominated operation and maintenance expenses with respect to
the Malitbog Project and Philippine withholding taxes, if any, on the
Malitbog Project's debt service. The Government of the Philippines has
entered into a performance undertaking (the "Performance Undertaking"),
which provides that all of PNOC-EDC's obligations pursuant to the
Malitbog ECA carry the full faith and credit of, and are affirmed and
guaranteed by, the Government of the Philippines.
PNOC-EDC is obligated to purchase VGPC's interest in the facility
under certain circumstances, including (i) certain material changes in
policies or laws which adversely affect VGPC's interest in the project,
(ii) any event of force majeure which delays performance by more than
90 days and (iii) certain other events. The price will be the net
present value of the capital cost recovery fees that would have been
due for the remainder of the Cooperation Period with respect to such
generating unit(s).
The Malitbog ECA cooperation period will expire ten years after
the date of commencement of commercial operation of Unit III. At the
end of the cooperation period, the facility will be transferred to PNOC-
EDC at no cost, on an "as is" basis. All of PNOC-EDC's obligations
under the Malitbog ECA are supported by the Government of the
Philippines through a performance undertaking. The capacity fees are
100% of total revenues and there is no energy fee.
Casecnan. In November 1995, the Company closed the financing and
commenced construction of the Casecnan Project, a combined irrigation
and 150 net MW hydroelectric power generation project (the "Casecnan
Project") located in the central part of the island of Luzon in the
Republic of the Philippines. The Casecnan Project will consist
generally of diversion structures in the Casecnan and Denip Rivers that
will divert water into a tunnel of approximately 23 kilometers. The
tunnel will transfer the water from the Casecnan and Denip Rivers into
the Pantabangan Reservoir for irrigation and hydroelectric use in the
Central Luzon area. An underground powerhouse located at the end of
the water tunnel and before the Pantabangan Reservoir will house a
power plant consisting of approximately 150 MW of newly installed rated
electrical capacity. A tailrace tunnel of approximately three
kilometers will deliver water from the water tunnel and the new
powerhouse to the Pantabangan Reservoir, providing additional water for
irrigation and increasing the potential electrical generation of two
downstream existing hydroelectric facilities of the NPC.
CE Casecnan Water and Energy Company, Inc., a Philippine
corporation ("CE Casecnan") which is presently indirectly owned as to
approximately 70% of its equity 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 the
CE Casecnan upon the occurrence of certain events, including increases
in Philippine taxes and adverse changes in Philippine law. Upon the
occurrence and during the continuance of certain force majeure events,
including those associated with Philippines political action, NIA may
be obligated to buy the Casecnan Project from CE Casecnan at a buy out
price expected to be in excess of the aggregate principal amount of the
outstanding CE Casecnan debt securities, together with accrued but
unpaid interest. At the end of the Cooperation Period, the Casecnan
Project will be transferred to NIA and NPC for no additional
consideration on an "as is" basis.
The Republic of the Philippines has provided a Performance
Undertaking under which NIA's obligations under the Project Agreement
are guaranteed by the full faith and credit of the Republic of the
Philippines. The Project Agreement and the Performance Undertaking
provide for the resolution of disputes by binding arbitration in
Singapore under international arbitration rules.
The Casecnan Project was being constructed pursuant to a fixed-
price, date-certain, turnkey construction contract (the "Hanbo
Contract") on a joint and several basis by Hanbo Corporation ("Hanbo")
and Hanbo Engineering and Construction Company Ltd. ("HECC"), both of
which are South Korean corporations. As of May 7, 1997, CE Casecnan
terminated the Hanbo Contract due to defaults by Hanbo and HECC
including the insolvency of each such company. CE Casecnan entered
into a new turnkey engineering, procurement and construction contract
to complete the construction of the Casecnan Project (the "Replacement
Contract"). The work under the Replacement Contract will be conducted
by a consortium of contractors and subcontractors including Siemens
A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering
Ltd. and will be headed by Cooperativa Muratori Cementisti CMC di
Ravenna and Impresa Pizzarotti & C. Spa (collectively, the "Replacement
Contractor").
In connection with the Hanbo Contract termination, CE Casecnan
tendered a certificate of drawing to Korea First Bank ("KFB") on May 7,
1997 under the irrevocable standby letter of credit issued by KFB as
security under the Hanbo Contract to pay for certain transition costs
and other presently ascertainable damages under the Hanbo Contract. As
a result of KFB's dishonor of the draw request, CE Casecnan filed an
action in New York State Court. That Court granted CE Casecnan's
request for a temporary restraining order requiring KFB to deposit
$79,329,000, the amount of the requested draw, in an interest bearing
account with an independent financial institution in the United States.
KFB appealed this order, but the appellate court denied KFB's appeal
and on May 19, 1997, KFB transferred funds in the amount of $79,329,000
to a segregated New York bank account pursuant to the Court order.
On August 6, 1997, CE Casecnan announced that it had issued a
notice to proceed to the Replacement Contractor. The Replacement
Contractor was already on site and thereafter fully mobilized and
commenced engineering, procurement and construction work on the
project.
On or about August 27, 1997 CE Casecnan received a favorable
summary judgment ruling in New York State Court against KFB. The
judgment, which has been appealed by the bank, requires KFB to honor
the $79,329,000 drawing by CE Casecnan on the $117,850,000 irrevocable
standby letter of credit.
On September 29, 1997, CE Casecnan tendered a second certificate
of drawing for $10,828,000 to KFB and on December 30, 1997, CE Casecnan
tendered a third certificate of drawing for $2,920,000 to KFB. KFB
also wrongfully dishonored these draws, but pursuant to a stipulation
agreed to deposit the draw amounts in an interest bearing account with
the same independent financial institution in the United States pending
resolution of the appeal regarding the first draw and agreed to
expedite the appeal.
The receipt of the letter of credit funds from KFB remains
essential and CE Casecnan will continue to press KFB to honor its clear
obligations under the letter of credit and to pursue Hanbo and KFB for
any additional damages arising out of their actions to date. If KFB
were to fail to honor its obligations, under the Casecnan letter of
credit, such action could have a material adverse effect on the
Casecnan Project and CE Casecnan.
On September 2, 1997, Hanbo and HECC filed a Request for
Arbitration before the International Chamber of Commerce ("ICC"). The
Request for Arbitration asserts various claims by Hanbo and HECC
against CE Casecnan relating to the terminated Hanbo Contract and seeks
damages. On October 10, 1997, CE Casecnan served its answer and
defenses in response to the Request for Arbitration as well as
counterclaims against Hanbo and HECC for breaches of the Hanbo
Contract. The arbitration proceedings before the ICC are ongoing and
CE Casecnan intends to pursue vigorously its claims against Hanbo, HECC
and KFB in the proceedings described above.
Indonesia Operations and Construction
Dieng. On December 2, 1994, a subsidiary of the Company, Himpurna
California Energy Ltd. ("HCE") executed a joint operation contract (the
"JOC") for the development of the geothermal steam field and geothermal
power facilities at the Dieng geothermal field, located in Central Java
(the "Dieng Project") with Perusahaan Pertambangan Minyak Dan Gas Bumi
Negara ("Pertamina"), the Indonesian national oil company, and executed
a "take-or-pay" energy sales contract (the "ESC") with both Pertamina
and PLN, the Indonesian national electric utility. HCE was formed
pursuant to a joint development agreement with P.T. Himpurna Enersindo
Abadi ("P.T. HEA"), its Indonesian partner, which is a subsidiary of
Himpurna, an association of Indonesian military veterans, whereby the
Company and P.T. HEA have agreed to work together on an exclusive basis
to develop the Dieng Project (the "Dieng Joint Venture"). Subsequent
to closing the KDG Acquisition in January 1998, the Dieng Joint Venture
is structured with subsidiaries of the Company holding an approximate
94% interest (including certain assignments of dividend rights
representing an economic interest of 4%), and P.T. HEA holding a 6%
interest in the Dieng Project.
All government approvals for Units I (55 net MW) and II (80 net
MW) necessary for closing were received, including a support letter
from the Republic of Indonesia, an off-shore loan board approval,
consents to assignment from the Republic of Indonesia, PLN and
Pertamina, and all required environmental approvals. Financial closing
for Unit I occurred on October 3, 1996, and construction for financing
for Unit II was funded on November 17, 1997.
Pursuant to the Dieng JOC and ESC, Pertamina has granted to HCE
the geothermal field and the wells and other facilities presently
located thereon and HCE will build, own and operate power production
units with an aggregate capacity of up to 400 MW. HCE will accept the
field operation responsibility for developing and supplying the
geothermal steam and fluids required to operate the plant.
The Dieng JOC is structured as a build own transfer agreement and
will expire (subject to extension by mutual agreement) on the date
which is the later of (i) 42 years following effectiveness of the Dieng
JOC and (ii) 30 years following the date of commencement of commercial
generation of the final unit. Upon the expiration of the proposed
Dieng JOC, all facilities will be transferred to Pertamina at no cost.
HCE is required to pay Pertamina a production allowance equal to three
percent of HCE's net operating income from the Dieng Project.
Pursuant to the Dieng ESC, PLN agreed to purchase and pay for all
of the Project's capacity and energy output on a "take or pay" basis
regardless of PLN's ability to accept such energy made available from
the Dieng Project for a term equal to that of the Dieng JOC. The price
paid for electricity includes a base energy price per kWh multiplied by
the number of kWhs the plants deliver or are "capable of delivering",
whichever is greater. Energy price payments are also subject to
adjustment for inflation. PLN will also pay a capacity payment based
on plant capacity. All such payments are payable in U.S. dollars.
PT Kiewit/Holt Indonesia, an affiliate of PKS, executed agreements
to construct Dieng Unit I and Unit II pursuant to a fixed price, date
certain, turnkey construction contract. Affiliates of PKS will provide
the engineered supply with respect to Dieng Unit I and Unit II pursuant
to a fixed price, date certain, turnkey supply contract.
Patuha. The Company's subsidiary, Patuha Power, Ltd. ("PPL")
executed a JOC and ESC with Pertamina and PLN, respectively on
substantially the same terms as the Dieng project. The Patuha project
is located in Western Java. All government approvals for Patuha Unit I
(80 net MW) necessary for closing were received, including a support
letter from the Republic of Indonesia, on offshore loan board approval,
consents to assignment from the Republic of Indonesia, PLN and
Pertamina, and all required environmental approvals. Construction
financing was funded for Patuha Unit I in September 1997. Patuha Unit
I is being constructed by PT Kiewit/Holt Indonesia pursuant to a fixed
price, date certain, turnkey construction contract. Affiliates of PKS
will provide engineered supply with respect to Patuha Unit I pursuant
to a fixed price, date certain, turnkey supply contract.
Bali. Significant infrastructure construction and well drilling
has occurred at the Bali site, but power plant construction has not
commenced.
On about June 12, 1997, the Company's special purpose subsidiary,
CE Indonesia Funding Corp., entered into a $400 million revolving
credit facility (which is nonrecourse to the Company) to finance the
development and construction of the Company's geothermal power
facilities in Indonesia. Funding under such facility has occurred for
Dieng Unit I, Dieng Unit II and Patuha Unit I.
Recent Presidential Decrees in Indonesia have created
uncertainties regarding the Company's Indonesian activities resulting
in the Company recognizing an $87 million non-recurring charge in the
fourth quarter of 1997. The Company is proceeding cautiously and is
actively pursuing resolution of the issues involving the Indonesian
projects in order to protect the Company's interests. Less than five
percent of the Company's total assets are invested in Indonesia. The
Company intends to take all actions necessary to ensure the Government
of Indonesia honors the project contracts.
Economies of emerging countries typically experience periods of
success and periods of setback. The Company's projects in emerging
regions have been and will continue to be structured to minimize risk
and have consistently obtained political risk insurance for investments
and sovereign guarantees for our projects in Indonesia. In addition,
payments in accordance with the project contracts, are in U.S. dollars
and therefore are not directly affected by local currency fluctuations.
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 accompanying
Prospectus.
United States
Salton Sea Minerals Extraction. The Company has developed a
process providing 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. The initial
phase of the project would require delivery of at least 15 MW of power.
A pilot plant has successfully produced commercial quality zinc at the
Company's Imperial Valley Project. Zinc is primarily used in
galvanizing steel for use in the automobile industry. 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, 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. Under a Bonneville Power Administration ("BPA")
geothermal pilot program, the Company has been developing a 30 net MW
geothermal project which was originally located in the Newberry Known
Geothermal Resource Area in Deschutes County, Oregon (the "Telephone Flat
Project"). The BPA contract arrangements have been amended to reflect the
relocation of the project to Telephone Flat in Northern California where
the Company has two successful production wells. Under the amended BPA
contract arrangements, BPA will purchase 30 MW from the project and has an
option to purchase an additional 100 MW. The movement of the project to
this alternative location and BPA's purchase obligation are subject to
obtaining a final environmental impact statement relating to the new site
location.
United Kingdom
Exeter. Exeter Power Limited ("Exeter") is a company owned 50% by
Northern Electric Generation Limited and 50% by Rolls-Royce Power
Ventures. Exeter is developing a 50 net MW gas-fired power plant at
Exeter, England. This project is based upon the U.K. "Mid-merit" model
(described below) and will be managed and operated by Northern upon
commercial operation. The power purchase contract and permits for the
project are currently being finalized.
U.K. Mid-merit Projects. The Company, through Northern Generation,
is pursuing a number of "Mid-merit" project opportunities in addition
to Exeter and Viking (which is under construction), in conjunction with
and separate from Rolls-Royce. "Mid-merit" projects are those projects
which have generation units having a registered capacity of 50 net MW
or less. As a result, these projects only require local planning
permission and limited central government permits. In addition, these
projects are connected to the local distribution system and not the
National Grid, which means these projects do not have to be a member of
the Pool and pay generator related grid and Pool charges.
These Mid-merit generating projects are also not subject to
central dispatch by the National Grid and therefore allow for the
potential of gas arbitrage between the electricity day-ahead pool
market and the within-day gas spot market. Northern supplies gas to
these projects through a gas tolling contract arrangement.
Finally, these projects are based on open (simple) cycle aero
derivative gas turbines which are ideally suited to multiple start/stop
operations. This flexible capability provides significant economic
benefits to Northern's electricity supply business in buying
electricity from the Mid-merit plant and avoiding pool purchases at
high pool price times and making Pool purchases when the Pool price is
below the Mid-merit plant's marginal costs.
U.K. Gas Transportation and Storage. The Company, through CE Gas,
is pursuing a number of gas transportation and storage opportunities in
the U.K. to integrate with its North Sea upstream gas production
operations.
Philippines
Alto Peak. The Alto Peak Project is a smaller geothermal project
in the same general area of Leyte as the Upper Mahiao, Mahanagdong and
Malitbog Projects. A subsidiary of the Company and PNOC-EDC have
executed a 70 net MW Energy Conversion Agreement, dated May 7, 1994.
The general terms and conditions are similar to the Malitbog Energy
Conversion Agreement ("ECA"). However, the plant design has not been
initiated because PNOC-EDC has not finalized the steam conditions
(pressure, composition and pH). PNOC-EDC is still drilling and testing
the geothermal wells that will supply steam to such project.
Consequently, the ECA has been extended and the Company has not
commenced financing arrangements for the Alto Peak Project.
Indonesia
Dieng Phase II, Patuha Phase II and Bali. The Company's Dieng,
Patuha and Bali projects in Indonesia represent ongoing, development
programs of 985 MW under contract, to be brought into commercial
operation on a modular basis as the steam fields are drilled and
developed. However, the situation in Indonesia has created some
significant challenges for the Company, requiring an $87 million non-
recurring charge in the fourth quarter of 1997.
Producing Gas Field Operations and Fields in Development
CE Gas UK Limited. CE Gas UK Limited ("CE Gas") is a gas
exploration and production company which is focused on developing
integrated upstream gas projects. Its "upstream gas" business consists
of the exploration, development and production, including
transportation and storage, of gas for delivery to a point of sale into
either a gas supply market or a power generation facility. CE Gas holds
various interests in the southern basin of the United Kingdom sector of
the North Sea, as described below. Also as is more fully discussed
below, CE Gas has recently been involved in certain gas development and
exploration activities relating to a large gas field prospect in Poland
and the Gingin field in the Perth Basin in Australia.
The Company's Producing Gas Field Operations and Fields in Development
PRODUCING GAS FIELDS SHARE OF CURRENT LOCATION
REMAINING % WORKING
RESERVES INTEREST
BCF(1)
Windermere 15.0 20% U.K. Offshore
(North Sea)
Victor 12.1 5% U.K. Offshore
(North Sea)
Schooner 11.1 2% U.K. Offshore
(North Sea)
Johnston 18.0 18.264% U.K. Offshore
(North Sea)
FIELDS IN DEVELOPMENT Size Km2
Gingin Concession 2,960 9%(2) S.W. Australia
Onshore
(Perth Basin)
Pila Concession 13,000(3) 100% N.W. Poland
(Polish Trough)
(1)Gas reserves in Billion cubic feet (or "Bcf") as of December 31, 1997.
The Classification "Remaining" means reserves which geophysical, geological
and engineering data indicate to be in place or recoverable (as the case
may be) with a 50% probability the reserves will exceed the estimate.
(2)Currently CE Gas beneficially owns 9% of Gingin Concession with a right
to earn up to a 50% working interest.
(3)Subject to 25% relinquishment after every 2 years during the 8 year
contract term based on work program results.
Producing Fields
Windermere Field (Producing). 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 15.0 bcf net to
CE Gas. The field is produced by an unmanned platform which has two
wells. The gas is transported via an 8" pipeline to the Markham Field
where it is processed, compressed and delivered through the K13
pipeline system to the Den Helder terminal on the Netherlands coast. CE
Gas holds a 20% working interest in this field which commenced
production in April 1997 and currently has average net daily production
of 9.0 MM scfd (million standard cubic feet per day). Gas is sold to
N.V. Nederlandse Gasunie.
Victor Field (Producing). The Victor gas field is located in the
central part of the Southern North Sea, approximately 80 miles east of
the Theddlethorpe terminal on the U.K. coast and has net Remaining
reserves of 12.1 bcf net to CE Gas. An unmanned platform is installed
and the field produces from 5 production wells and a sixth subsea well
tied back to the platform. The gas is exported through a 16" pipeline
to the Viking field and then onwards to the Theddlethorpe shore
terminal. The Victor field has been in production since September 1984,
and currently has average daily production of 5.94 MM scfd and sells
its gas to British Gas Trading Limited. CE Gas holds a 5% working
interest in this field.
Schooner Field (Producing). The Schooner Field is located in the
Northern part of the Southern North Sea and has Remaining reserves of
11.1 bcf. The field is produced by an unmanned platform which is tied
back through a 28km 16" flowline to the Murdoch platform. Production is
achieved from four wells with a fifth well planned this year. 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 daily production of 1.8 MM scfd. The CE Gas share of the gas is
sold to its affiliate Northern.
Johnston Field (Producing). The Johnston gas field is located in
the Southern North Sea approximately 56 miles north east of Scarborough
on the U.K. coast and has Remaining reserves of 18 bcf net to CE gas.
The field is produced from three subsea wells tied back to the
Ravenspurn North field via a 4.5 mile, 12" pipeline. Gas is exported
via the Cleeton field to the Dimlington terminal via a 33 mile, 36"
pipeline. The Johnston field has been in production since October 1994
at an average daily rate of 53 MMscfd. Gas is sold to Eastern Natural
Gas. CE Gas has a 18.264% working interest in this field.
Fields in Development
Pila. In August 1997, CE Gas signed an eight year concession
development agreement with the Polish government providing it with the
exclusive right (a 100% working interest) to develop the extensive
(13,000 square kilometers) undeveloped Pila gas concession in the
Polish Trough in northwest Poland. CE Gas is committed to a seismic and
drilling work program to develop producing areas within the concession
over that period, subject to relinquishment of up to 25% of the
concession area after every two years, with only developed areas to be
retained by CE Gas at the end of the eight year term. The Company
believes that there is the potential to structure an integrated
upstream gas/power generation project at the Pila concession, subject
to (among other things) identifying a suitable site and negotiating an
acceptable power offtake agreement.
Gingin Gas Field. In August 1997, CE Gas signed an earn-in
agreement with Empire Gas of Australia, the permit holder for various
concession areas in the Gingin field in the Perth Basin in Western
Australia. The earn-in agreement provides CE Gas with the ability,
through a seismic and drilling phased work program, to obtain up to a
50% working interest in the main concession area totaling 2,960 square
kilometers and up to a 33% working interest in four ancillary
concession areas totaling 9,451 square kilometers. Gingin gas reserves
are estimated by Empire Gas to be 470 bcf. Given the advantages of the
location of the Gingin field, in close proximity to an industrial area
and electric residential load center, the Company believes that the
Gingin field possesses the potential for an integrated upstream
gas/power generation project.
Both electricity and gas are in the process of being opened up for
competition. 95% of all gas to SW Australia is currently supplied from
the NW shelf (Dampier to Bunbury pipeline--1500km). The Onshore Perth
Basin is known to be gas prone but has been significantly underexplored
and underdeveloped. Historically, gas has been a state controlled
energy sector in Australia. The Gingin field proved gas in the early
1970s. The Company believes that new technologies now offer the
potential for extracting significant gas reserves through more advanced
recovery methods, and the Company, which currently beneficially owns a
9% interest in the Gingin Concession, has the right to earn up to a 50%
working interest under its phased seismic and drilling work program
with Empire Gas of Australia.
Regulatory, Energy and Environmental Matters
United States
The Company is subject to a number of environmental laws and other
regulations affecting many aspects of its present and future
operations, including the construction or permitting of new and
existing facilities, the drilling and operation of new and existing
wells and the disposal of various geothermal solids. Such laws and
regulations generally require the Company to obtain and comply with a
wide variety of licenses, permits and other approvals. No assurance can
be given, however, that in the future all necessary permits and
approvals will be obtained and all applicable statutes and regulations
complied with. In addition, regulatory compliance for the construction
of new facilities is a costly and time-consuming process, and intricate
and rapidly changing environmental regulations may require major
expenditures for permitting and create the risk of expensive delays or
material impairment of project value if projects cannot function as
planned due to changing regulatory requirements or local opposition.
The Company believes that its operating power facilities are currently
in material compliance with all applicable federal, state and local
laws and regulations. There can be no assurance that existing
regulations will not be revised or that new regulations will not be
adopted or become applicable to the Company which could have an adverse
impact on its operations. In particular, the independent power market
in the United States is dependent on the existing energy regulatory
structure, including PURPA and its implementation by utility
commissions in the various states.
Each of the Company's operating domestic power facilities meets
the requirements promulgated under PURPA to be qualifying facilities.
Qualifying facility status under PURPA provides two primary benefits.
First, regulations under PURPA exempt qualifying facilities from the
Public Utility Holding Company Act of 1935, as amended ("PUHCA"), most
provisions of the Federal Power Act (the "FPA") and the state laws
concerning rates of electric utilities, and financial and organization
regulations of electric utilities. Second, FERC's regulations
promulgated under PURPA require that (1) electric utilities purchase
electricity generated by qualifying facilities, the construction of
which commenced on or after November 9, 1978, at a price based on the
purchasing utility's full Avoided Cost, (2) the electric utility sell
back-up, interruptible, maintenance and supplemental power to the
qualifying facility on a non-discriminatory basis, and (3) the electric
utility interconnect with a qualifying facility in its service
territory.
Currently, Congress is considering proposed legislation that would
amend PURPA by eliminating the requirement that utilities purchase
electricity from qualifying facilities at prices based on Avoided
Costs. The Company does not know whether such legislation will be
passed or what form it may take. The Company believes that if any such
legislation is passed, it would apply to new projects only and thus,
although potentially impacting the Company's ability to develop new
domestic projects, it would not affect the Company's existing
qualifying facilities. There can be no assurance, however, that any
legislation passed would not adversely impact the Company's existing
domestic projects.
In addition, many states are implementing or considering
regulatory initiatives designed to increase competition in the domestic
power generation industry and increase access to electric utilities'
transmission and distribution systems for independent power producers
and electricity consumers. On September 1, 1996, the California
legislature adopted an industry restructuring bill that would provide
for a phased-in competitive power generation industry with a power pool
and independent system operator and also would permit direct access to
generation for all power purchasers outside the power exchange under
certain circumstances. Under the bill, consistent with the requirements
of PURPA, existing qualifying facilities power sales agreements would
be honored. The Company cannot predict the final form or timing of the
proposed industry restructuring or the results of its operations.
The structure of such federal and state energy regulations have in
the past, and may in the future, be the subject of various challenges
and restructuring proposals by utilities and other industry
participants. The implementation of regulatory changes in response to
such changes or restructuring proposals, or otherwise imposing more
comprehensive or stringent requirements on the Company, which would
result in increased compliance costs, could have a material adverse
effect on the Company's results of operations.
United Kingdom
Northern's businesses are subject to numerous regulatory
requirements with respect to the protection of the environment. The
Electricity Act obligates the UK Secretary of State or the Regulator to
take into account the effect of electricity generation, transmission
and supply activities upon the physical environment when approving
applications for the construction of generating facilities and the
location of overhead power lines. The Electricity Act requires Northern
to consider the desirability of preserving natural beauty and the
conservation of natural and man-made features of particular interest,
when it formulates proposals for development in connection with certain
of its activities. Northern mitigates the effects its proposals have on
natural and man-made features and administers an environmental
assessment when it intends to lay cables, construct overhead lines or
carry out any other development in connection with its licensed
activities.
The Environmental Protection Act 1990 addresses waste management
issues and imposes certain obligations and duties on companies which
handle and dispose of waste. Some of Northern's distribution activities
produce waste, but Northern believes that it is in compliance with the
applicable standards in such regard.
Possible adverse health effects of electromagnetic fields ("EMFs")
from various sources, including transmission and distribution lines,
have been the subject of a number of studies and increasing public
discussion. Current scientific research is inconclusive as to whether
EMFs may cause adverse health effects. The only United Kingdom
standards for exposure to power frequency EMFs are those promulgated by
the National Radiological Protection Board and relate to the levels
above which non-reversible physiological effects may be observed.
Northern fully complies with these standards. However, there is the
possibility that passage of legislation and change of regulatory
standards would require measures to mitigate EMFs, with resulting
increases in capital and operating costs. In addition, the potential
exists for public liability with respect to lawsuits brought by
plaintiffs alleging damages caused by EMFs.
Northern believes that it has taken and continues to take measures
to comply with the applicable laws and governmental regulations for the
protection of the environment. There are no material legal or
administrative proceedings pending against Northern with respect to any
environmental matter.
In the general election held in the United Kingdom on May 1, 1997,
the Labour Party won a majority of seats in the United Kingdom
Parliament. On July 31, 1997, the United Kingdom Parliament passed the
so called "windfall tax" to be levied on privatized utilities which
resulted in a charge to net income of approximately $136 million. See
the Company's Current Report on Form 8-K dated July 7, 1997,
incorporated herein by reference. There can be no assurance that other
possible changes in tax or utility regulation by the United Kingdom
government, by whichever party it is controlled, would not have a
material adverse effect on the Company's results of operations. In
March 1998 the Government published a consultation on utility
regulation. This paper outlined a number of proposals for discussion.
The stated objectives are "fairness and efficiency" which the
Government regard as "the key to securing a long-term, stable and
effective framework capable of serving consumers well and of taking
these industries into the next millennium". Some of the proposals
under consideration would require legislative changes.
Employees
At December 31, 1997, the Company and its subsidiaries (including
Northern) employed approximately 4,300 people. None of the Coso
Partnerships, the Falcon Project nor the Imperial Valley Project
partnerships hire or retain any employees. All employees necessary to
the operation of the Coso Project are provided by the Company under
certain plant and field operations and maintenance agreements. All
employees necessary to operate the Falcon and Imperial Valley Projects
are provided by affiliates of the Company under certain administrative
services and operation and maintenance agreements. International
development activities in Indonesia and the Philippines are principally
performed by employees of affiliates of the Company and operations will
be performed by employees of the local project entities. The Company's
affiliates currently maintain offices in Manila and Jakarta.
Of Northern's employees, at December 31, 1997, approximately 86%
are represented by labor unions. All Northern employees who are not
party to a personal employment contract are subject to collective
bargaining agreements that are covered by eight separate business
agreements. These arrangements may be amended by joint agreement
between the trade unions and the individual business through
negotiation in the appropriate Joint Business Council. Northern
believes that its relations with its employees are good.
Item 2. Properties
Property. The Company's most significant physical properties,
other than those owned by Northern (described herein), are its 21
operating power facilities, its plants under construction and related
real property interests. The Company also maintains an inventory of
approximately 200,000 acres of geothermal property leases. The Company
owns its principal executive offices and leases its offices in Jakarta
and Manila. Certain of the producing acreage owned by Magma is leased
to Mammoth-Pacific as owner and operator of the Mammoth Plants, and
Magma, as lessor, receives royalties from the revenues earned by such
power plants. The Company, as lessee, pays certain royalties and other
fees to the property owners and other royalty interest holders from the
revenue generated by the Imperial Valley Project.
Lessors and royalty holders are generally paid a monthly or annual
rental payment during the term of the lease or mineral interest unless
and until the acreage goes into production, in which case the rental
typically stops and the (generally higher) royalty payments begin.
Leases of federal property are transacted with the Department of
Interior, Bureau of Land Management, pursuant to standard geothermal
leases under the Geothermal Steam Act and the regulations promulgated
thereunder (the "Regulations"), and are for a primary term of 10 years,
extendible for an additional five years if drilling is commenced within
the primary term and is diligently pursued for two successive five-year
periods upon certain conditions set forth in the Regulations. A
secondary term of up to 40 years is available so long as geothermal
resources from the property are being produced or used in commercial
quantities. Leases of state lands may vary in form. Leases of private
lands vary considerably, since their terms and provisions are the
product of negotiations with the landowners.
Northern owns the freehold of its principal executive offices in
Newcastle upon Tyne, England. Northern has both network and non-network
land and building. At December 31, 1997, Northern had freehold and
leasehold interests in approximately 7,500 network properties,
comprising principally sub-station sites. The recorded historical cost
account net book value of total network land and buildings at December
31, 1997 was pounds sterling 23.9 million. Northern owns, directly or
indirectly, the freehold or leasehold interests of such land and
buildings. At December 31, 1997 Northern had freehold and leasehold
interests in approximately 102 non-network properties comprising
chiefly offices, former retail outlets, depots, warehouses and
workshops. The recorded historical cost account net book value of total
non-network land and buildings at December 31, 1997 was pounds sterling
25.6 million.
Item 3. Legal Proceedings
The Company is not a party to any material pending legal
proceedings. However, as described herein, certain of the Company's
projects are parties to litigation or other disputes.
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder's Matters
The Common Stock is listed on the New York Stock Exchange (the
"NYSE"), the Pacific Stock Exchange and the London Stock Exchange under
the symbol "CE." The following table sets forth for the fiscal quarters
indicated the high and low last reported sale prices of the Common
Stock as reported on the NYSE Composite Tape.
PRICE
RANGE
HIGH LOW
Fiscal Year Ending
December 31, 1997
Fourth Quarter 39.625 28.00
Third Quarter 41.75 30.9375
Second Quarter 41.625 32.625
First Quarter 38.375 32.125
Fiscal Year Ending
December 31, 1996
Fourth Quarter 33.625 28.125
Third Quarter 31.875 22.875
Second Quarter 28.375 24.00
First Quarter 26.875 18.375
Fiscal Year Ending
December 31, 1995
Fourth Quarter 20.875 17.875
Third Quarter 21.50 16.125
Second Quarter 17.125 15.50
First Quarter 18.875 15.375
On March 23, 1998, the last reported sale price of the Common
Stock on the NYSE Composite Tape was $30 7/8 per share. As of March 23,
1998, there were approximately 1,091 holders of record of the Common
Stock. The Company's present policy is to reinvest earnings in the
business and pay no dividends on its Common Stock. In addition, certain
of the Company's current debt indentures restrict the payment of cash
dividends based upon a formula and limit the amount of dividends and
other distributions generally to no more than 50% of the Company's
accumulated adjusted consolidated net income as defined, subsequent to
April 1, 1994, plus the proceeds of any stock issuances.
The Company's 10-1/4% senior discount notes due 2004, the
Company's 9 1/2% senior notes due 2006 and the Company's 7.63% senior
notes due 2007 restrict the payment of cash dividends based upon a
formula and limit the amount of dividends and other distributions
generally to no more than 50% of the Company's accumulated adjusted
consolidated net income as defined, subsequent to April 1, 1994, plus
the proceeds of any stock issuance.
The Company's ability to pay dividends is dependent upon receipt
of dividends or other distributions from the Company's subsidiaries and
the partnerships and joint ventures in which the Company has interests.
The availability of distributions from the Company's joint ventures is
subject to the satisfaction of various covenants and conditions
contained in the venture's financing documents (such as those contained
in the Salton Sea Funding, Coso Funding, or international project
financing documents) and the Company anticipates that future project
level financings will contain certain conditions and similar
restrictions on the distribution of cash flow to the Company.
Item 6. Selected Financial Data
There is hereby incorporated by reference the information which
appears under the caption "Selected Financial Data" in the Annual
Report.
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operation
There is hereby incorporated by reference the information which
appears under the caption "Management's Discussion and Analysis of
Financial Condition and Results of Operations" in the Annual Report.
Item 8. Financial Statements and Supplementary Data
There is hereby incorporated by reference the information which
appears in the Consolidated Financial Statements and notes thereto in
the Annual Report.
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure
Not applicable.
PART III
MANAGEMENT
Item 10. Directors, Executive and Other Officers of the Company
There is hereby incorporated by reference the information which
appears under the caption "Information Regarding Nominees for Election
as Directors and Directors Continuing in Office at the Annual Meeting"
in the Proxy Statement. The Company's management structure is organized
functionally and the current executive and other officers of the
Company and their positions are as follows:
David L. Sokol Chairman of the Board and Chief Executive Officer
Gregory E. Abel President and Chief Operating Officer
Steven A. McArthur Executive Vice President, General Counsel and Secretary
Craig M. Hammett Senior Vice President and Chief Financial Officer
Douglas L. Anderson Assistant General Counsel, Assistant Secretary
and General Counsel, CalEnergy Operating Company
David A. Baldwin General Manager, Philippines
Edward F. Bazemore Vice President, Human Resources
Robert Beck Director, Information Systems
Donald C. Blachly General Manager, Coso Geothermal Operations
Malcolm Chandler Director, Northern Electric and Managing Director, Supply
P. Eric Conner Director, Northern Electric and Managing Director,
Utility Services
Dave Crompton Managing Director, Northern Electric, Retail
Richard B. Dalton General Manager, Leyte Geothermal Operations
Alan Dickson Tax Manager, Northern Electric
J. Douglas Divine Vice President, Project Development
David A. Faulkner Director, Personnel and Corporate Affairs,
Northern Electric
John L. Featherstone General Manager, Minerals
Vincent R. Fesmire Vice President, Construction and Engineering
James A. Flores Vice President, Project Finance
Adrian M. Foley III Vice President, Marketing
Dr. John M. France Regulation Director, Northern Electric
G. Valerie Giles Company Secretary, Northern Electric
Patrick J. Goodman Vice President, Chief Accounting Officer and Controller
Brian K. Hankel Vice President and Treasurer
Edward J. Heinrich General Manager, U.S. Gas Operations
Gary L. Hood General Manager, NorCon Gas Operations
Walter Keenan Director, Human Resources
Dr. Philip S. Lawless Managing Director, Generation, Northern Electric
Kenneth R. Lewis General Manager, Power Resources Gas Operations
Ken Linge Director, Financial Planning, Northern Electric
Steven G. Lyons Project Manager, Casecnan
Thomas R. Mason President, CalEnergy Operating Company
Frederick L. Manuel Vice President and Chief Operating Officer, Asia
Patti J. McAtee Director, Corporate Communications
Neil W. Midgley Managing Director, Northern Metering Services
Donald M. O'Shei, Jr. President, CalEnergy Development Company
David Pearson Managing Director, Marketing and Sales,
Northern Electric
Steve Raine Managing Director, Northern Information
Systems and Northern Electric Telecom
P. Dan Rorabaugh General Manager, Saranac Gas Operations
John A. Schretlen General Manager, Yuma Gas Operations
James J. Sellner Director, Taxation
Robert S. Silberman Senior Vice President, Administration
James D. Stallmeyer General Counsel, Northern Electric and General
Counsel, CalEnergy Development Company
David Swan Director, Northern Electric and Managing
Director, Distribution
James T. Turner General Manager, Imperial Valley Geothermal Operations
David A. Waters Managing Director, Northern Utility Services
Jonathan M. Weisgall Vice President, Legislative and Regulatory Affairs
Peter Youngs Managing Director, Gas Exploration and Development
Set forth below is certain information with respect to each of the
foregoing officers:
DAVID L. SOKOL, 41, Chairman of the Board of Directors and Chief
Executive Officer. Mr. Sokol has been CEO since April 19, 1993 and
served as President of CalEnergy 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, 35, President and Chief Operating Officer. Mr.
Abel joined the Company in 1992. Mr. Abel is a Chartered Accountant and
from 1984 to 1992 he was employed by Price Waterhouse. As a Manager in
the San Francisco office of Price Waterhouse, he was responsible for
clients in the energy industry.
STEVEN A. McARTHUR, 40, Executive Vice President, General Counsel
and Secretary. Mr. McArthur joined the Company in February 1991. From
1988 to 1991 he was an attorney in the Corporate Finance Group at
Shearman & Sterling in San Francisco. From 1984 to 1988 he was an
attorney in the Corporate Finance Group at Winthrop, Stimson, Putnam &
Roberts in New York.
CRAIG M. HAMMETT, 37, Senior Vice President and Chief Financial
Officer. Mr. Hammett joined the Company in 1996. Prior to joining the
Company, Mr. Hammett served as Director of Project Finance for Energy
Power group, as Director, Project Finance and M&A for CSW Energy and as
a corporate loan officer for various financial institutions.
DOUGLAS L. ANDERSON, 40, Assistant General Counsel, Assistant
Secretary and General Counsel, CalEnergy Operating Company. Mr.
Anderson joined the Company in February 1993. From 1990 to 1993, Mr.
Anderson was a business attorney with Fraser, Stryker, Vaughn, Meusey,
Olson, Boyer & Bloch, P.C. in Omaha. From 1987 through 1989, Mr.
Anderson was a principal in the firm Anderson & Anderson. Prior to
that, from 1985 to 1987, he was an attorney with Foster, Swift, Collins
& Coey, P.C. in Lansing, Michigan.
DAVID A. BALDWIN, 33, General Manager, Philippines. Mr. Baldwin
joined the Company in June 1997. From December 1996 to June 1997, Mr.
Baldwin served as Vice President, Project Development for Asia Power
Ltd. in Hong Kong. From October 1994 to December 1996, Mr. Baldwin was
Project Director at SouthPac Corporation Ltd. in New Zealand and, prior
to that, he held a series of project management and engineering
positions at Shell International in the Netherlands and New Zealand.
EDWARD F. BAZEMORE, 61, Vice President, Human Resources. Mr.
Bazemore joined the Company in July 1991. From 1989 to 1991, he was
Vice President, Human Resources, at Ogden Projects, Inc. in New Jersey.
Prior to that, Mr. Bazemore was Director of Human Resources for Ricoh
Corporation, also in New Jersey. Previously, he was Director of
Industrial Relations for Scripto, Inc. in Atlanta, Georgia.
ROBERT BECK, 36, Director, Information Systems. Mr. Beck joined
the Company in April 1996. Prior to that he was employed by Inacom,
Corp., Sequoia Systems, Inc., AT&T - Brandon Consulting Group, U.S.
West Marketing Resources Group, Inc., United Phone Book Advertisers,
Inc. and Henningsen, Durham & Richardson ("HDR").
DONALD C. BLACHLY, 50, General Manager, Coso Geothermal
Operations. Mr. Blachly joined the Company in June 1993. Prior to that
Mr. Blachly had been employed by Santa Fe Geothermal and the Sacramento
Municipal Utility District in various management and engineering
capacities.
MALCOLM CHANDLER, 55, Director, Northern Electric and Managing
Director, Supply. Mr. Chandler joined Northern in 1970 from Manweb as
Tariffs Engineer. His management positions have included Tariffs &
Supplies Manager, Regional Manager and Director of Tariffs & Contracts.
ERIC CONNOR, 49, Director, Northern Electric and Managing
Director, Utility Services. Mr. Connor joined Northern in 1992 as a
Director. Prior to joining Northern, he was a Director at NEI Reyrolle
Ltd. and prior to that, his appointments included: deputy group head of
engineering, National Nuclear Corporation; manager computer systems,
NEI Electronics (C&I Systems); systems engineer, Davy-Leowy; software
engineer, Marconi Space & Defence.
DAVE CROMPTON, 44, 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.
RICHARD B. DALTON, 45, General Manager, Leyte Geothermal
Operations. Mr. Dalton joined the Company in November 1989. Prior to
that he was Plant Superintendent at Imperial Valley from 1987 to 1989.
From 1976 to 1987 Mr. Dalton was an Engineering Officer with the U.S.
Merchant Marines.
ALAN DICKSON, 49, Tax Manager, Northern Electric. Mr. Dickson
joined Northern in September 1989. Prior to that Mr. Dickson served in
various posts with the Inland Revenue and as District Inspector,
Hexham.
J. DOUGLAS DIVINE, 41, Vice President, Project Development. Mr.
Divine joined the Company in September 1996. Prior to that, he was
Director of Planning and Regulatory Affairs with Falcon Seaboard
Resources Inc. from 1990 to 1996. From 1987 to 1990, he was Senior
Manager of Management Consulting Services with Price Waterhouse; from
1984 to 1986 Mr. Divine was Director of Operations Review Divisions and
Executive Assistant to Commissioner of the Public Utility Commission of
Texas; and from 1983 to 1984, he was Coordinator of Revenue and
Economic Analysis for the Governor's Office, State of Texas.
DAVID A. FAULKNER, 50, Director, Personnel and Corporate Affairs,
Northern Electric. Mr. Faulkner's management positions with the Company
have included Industrial Relations Manager, Privatization Manager and
Director of Corporate Affairs, to which he added responsibility for
Personnel and Training in 1994.
JOHN L. FEATHERSTONE, 53, General Manager, Minerals. Mr.
Featherstone joined the Company in April 1996. From July 1995 to March
1996 he was Plant Manager with Unocal Geothermal of Indonesia. From
1993 to July 1995 he served in various supervisory capacities with the
Company. From 1981 to 1995 he was Production Engineer and Production
Superintendent for Unocal Geothermal.
VINCENT R. FESMIRE, 57, Vice President, Construction and
Engineering. Mr. Fesmire joined the Company in October 1993. Since
joining CalEnergy, Mr. Fesmire's responsibilities have shifted from
project development and implementation to construction in parallel with
the status of the Company's projects. Prior to joining the Company, Mr.
Fesmire was employed for 19 years with Stone & Webster, an engineering
firm, serving in various management level capacities with an expertise
in geothermal design engineering.
JAMES A. FLORES, 44, Vice President, Project Finance. Prior to
joining CalEnergy in May 1994, Mr. Flores was employed for 12 years
with Mellon Bank, first in its Latin American Group and subsequently in
its Project Finance Group.
ADRIAN M. FOLEY, III, 51, Vice President, Marketing. Mr. Foley
joined the Company in January 1994 as Project Development Manager and
continued in that capacity until January 1997 when he was promoted to
Vice President, Marketing. Prior to joining CalEnergy, Mr. Foley was
Regional Manager, Business Development with Ogden Projects, Inc. from
1989 to 1993 and Executive Vice President with Rescom Development
Company from 1980 to 1989.
DR. JOHN M. FRANCE, 40, Regulation Director, Northern Electric.
Mr. France joined Northern in 1989. From 1982 to 1989, Mr. France held
a number of regulatory positions with British Gas.
G. VALERIE GILES, 46, 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.
PATRICK J. GOODMAN, 31, Vice President, Chief Accounting Officer
and Controller. Mr. Goodman joined the Company in June 1995, and served
as Manager of Consolidation Accounting until September 1996 when he was
promoted to Controller. Prior to joining the Company, Mr. Goodman was
an accountant at Coopers & Lybrand.
BRIAN K. HANKEL, 35, 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.
EDWARD J. HEINRICH, 44, General Manager, U.S. Gas Operations. Mr.
Heinrich joined the Company in November 1993. Prior to the joining the
Company Mr. Heinrich was plant supervisor with Sithe Energies, Inc. and
prior to that he was with the United States Navy.
GARY L. HOOD, 43, General Manager, NorCon Gas Operations. Mr.
Hood joined NorCon Gas Operations in January 1997. Prior to that, Mr.
Hood held various positions at Saranac, the most recent position from
August 1996 to January 1997 as Operations Manager. From 1977 to the
mid 1990's Mr. Hood served in the U.S. Navy with positions as Nuclear
Machinists's Mate, Leading Petty Officer, Division Leading Petty
Officer, Crew Chief/Plant Division Leading Officer, Nuclear Planner and
Leading Crew Chief, Navy Nuclear Power Training Unit.
WALTER G. KEENAN, 42, Director, Human Resources. Mr. Keenan joined
CalEnergy in November 1991 as Director of Human Resources. From August
1990 to October 1991 he served as Human Resources Coordinator for
Texaco Refining & Marketing, Inc. Prior to that Mr. Keenan was Human
Resources Manager with Empire of America, FSB from September 1986 to
July 1990 and Employee Relations Manager Training/Development
Specialist with Gould Semiconductors from May 1982 to August 1986.
DR. PHILIP S. LAWLESS, 36, 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.
KENNETH R. LEWIS, 62, General Manager, Power Resources Gas
Operations. Mr. Lewis joined the Company as Manager for Power
Resources, Inc. after extensive power plant background during thirty-
two years of service with TU Electric. Mr. Lewis received his BSME
from the University of Oklahoma School of Engineering. He is a
Registered Professional Engineer and a member of the American Society
of Mechanical Engineers.
KEN LINGE, 48, Director, Financial Planning, Northern Electric.
Mr. Linge joined Northern as an accountancy trainee in 1968. He has
held a variety of finance posts. In charge of Financial Planning since
1987, he has been involved in privatization, regulatory reviews and
financial and treasury functions.
STEVEN G. LYONS, 51, Project Manager, Casecnan. Mr. Lyons joined
the Company in August 1997. Prior to that he was a Construction
Specialist and Senior Construction Engineer for Stone & Webster. Prior
to that he held a variety of engineering positions at various
generating facilities and was a construction Superintendent at the
Salton Sea plants.
THOMAS R. MASON, 54, President, CalEnergy Operating Company. Mr.
Mason joined the Company in March 1991. From October 1989 to March
1991, Mr. Mason was Vice President and General Manager of Kiewit Energy
Company. Prior to that, Mr. Mason was Director of Marketing for Energy
Factors, Inc. (now Sithe Energies U.S.A., Inc.), a non-utility
developer of power facilities. Prior to that Mr. Mason was a worldwide
Market Manager of power generation for Caterpillar's Solar Gas
Turbines, a gas turbine manufacturer.
FREDERICK L. MANUEL, 39, Vice President and Chief Operating
Officer, Asia. Mr. Manuel joined the Company in 1991. Prior to that, he
was employed by Chevron Corporation with responsibilities including
land and offshore drilling, reservoir and production engineering,
project management and technical research.
PATTI J. MCATEE, 40, Director, Corporate Communications. Marketing
and Public Relations Manager. Ms. McAtee joined the Company in 1995.
Ms. McAtee was previously employed by Bergan Mercy Medical Center since
1984. Since 1990 she was Marketing and Public Relations Manager for
the hospital.
NEIL W. MIDGLEY, 50, Managing Director, Northern Metering
Services. Mr. Midgley has spent more than 28 years in Northern
Electric with 18 years in management including seven years as a Senior
Manager prior to his current appointment. Mr. Midgley was appointed to
his present post in April 1996.
DONALD M. O'SHEI, JR., 38, President, CalEnergy Development
Company. Mr. O'Shei joined the Company in August 1992. Prior to 1997,
he served as General Manager--Indonesia and Vice President of CE
International Investments, Ltd. for the Company. From 1991 to 1992, he
was employed by Proven Alternatives Capital Corporation as a Financial
Analyst. Prior to 1991, Mr. O'Shei served in the U.S. Army in the
Special Forces, Airborne and Pathfinder Units.
DAVID PEARSON, 43, Managing Director, Marketing and Sales,
Northern Electric. Mr. Pearson joined Northern in 1992 as Managing
Director, Retail. Prior to that his directorships included Midlands
Electricity, Sodexho, Thorn EMI, and Moulinex UK. He also held
management positions at General Foods and Gilette.
STEVE RAINE, 51, Managing Director, Northern Information Systems
and Northern Electric Telecom. Mr. Raine's appointments have included:
Head of Computer Services for North Yorkshire County Council; Director
of IT at Northern; General Manager and Executive Director of Northern
Information Systems (NIS). He currently represents the UK electricity
industry in UNIPEDE (the European electricity utility forum) on IT
matters and is a member of the UK Electricity Pool Programme Board
responsible for delivery of the new trading systems for the opening up
of the electricity market.
P. DAN RORABAUGH, 36, General Manager, Saranac Gas Operations.
Mr. Rorabaugh joined the Company in 1996. Prior to joining the
Company, he was employed by Stewart & Stevenson Operations and Sithe
Energies, Inc. Prior to that time, Mr. Rorabaugh was with the United
States Navy in San Diego, California where he served as Gas Turbine
Technician.
JOHN A. SCHRETLEN, 35, General Manager, Yuma Gas Operations. Mr.
Schretlen joined the Company in September 1989. Prior to that, he
served as Maintenance Manager for Falcon Power Operating Company, Power
Resources, Inc. and Big Spring, Texas. Prior to joining CalEnergy, Mr.
Schretlen was employed by Custom Equipment Rebuilders, Inc., Amerada
Hess Company, Inc. and Callaway Aviation, Inc.
JAMES J. SELLNER, 51, Director, Taxation. Director Taxation. Mr.
Sellner joined CalEnergy in November, 1997. Prior to joining
CalEnergy, Mr. Sellner was employed by Central and South West
Corporation and Banc One/Mcorp.
ROBERT S. SILBERMAN, 40, Senior Vice President, Administration.
Mr. Silberman joined the Company in 1995. Prior to that, Mr. Silberman
served as Executive Assistant to the Chairman and Chief Executive
Officer of International Paper Company, as Director of Project Finance
and Implementation for the Ogden Corporation and as a Project Manager
in Business Development for Allied-Signal, Inc. He has also served as
the Assistant Secretary of the Army for the United States Department of
Defense.
JAMES D. STALLMEYER, 40, General Counsel, Northern Electric and
General Counsel, CalEnergy Development Company. 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, 53, Director, Northern Electric and Managing Director,
Distribution. Mr. Swan joined Northern in 1966 and has held posts in
varying disciplines including distribution, engineering design,
operations, customers engineering, customer relationships, engineering
contracting, logistics, computer systems development and project
management.
JAMES T. TURNER, 48, General Manager, Imperial Valley Geothermal
Operations. Mr. Turner joined the Company as Director of Engineering &
Technology for Magma Power Company in 1993. From 1974 to 1993 he held
various engineering positions with The Dow Chemical Company. Those
positions included Technical Manager, Engineering Manager and
Physicist.
DAVID A. WATERS, 55, Managing Director, Northern Utility Services.
Mr. Waters joined Northern in September 1960 as a Student Apprentice.
In 1982 he became a Resources Engineer and received appointments as
Cleveland (Teesside) Technical Distribution System Planning Manager,
Business Development Manager, later promoted to Business Services
Manager and General Manager, NUSL. The following March 1998 he was
appointed as Managing Director.
JONATHAN M. WEISGALL, 49, Vice President, Legislative and
Regulatory Affairs. Mr. Weisgall joined the Company in May 1995. Prior
to that, Mr. Weisgall was an attorney in private practice with
extensive energy and regulatory experience and is currently Adjunct
Professor of Energy Law at Georgetown University Law Center.
PETER YOUNGS, 43, 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 Sovereign Exploration Ltd. (now CalEnergy
Gas (UK) Limited).
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Financial Statements and Schedules
1. Financial Statements
Filed herewith and incorporated by reference are the
consolidated balance sheets of the Company and subsidiaries as of
December 31, 1997 and 1996, and the consolidated statements of
operations, cash flows and stockholders' equity for the years ended
December 31, 1997, 1996 and 1995, and the related report of independent
auditors.
2. Financial Statement Schedules
Independent Auditor's Report on Schedule I, Financial
Statements of the Company (Parent Company only)
The consolidated Magma financial statement schedules
which are excluded from the annual report to shareholders by Rule 14a-
3(b) are required by Regulation S-X (17 CFR 210) as Magma is an
affiliate whose securities are pledged as collateral and are included
at Item 14(d).
(b) Reports on Form 8-K
The Company filed a Current Report on Form 8-K dated October
9, 1997 reporting the investment grade credit rating of the Company's
senior unsecured debt by Duff & Phelps Credit Rating Co.
The Company filed a Current Report on Form 8-K dated October
13, 1997 reporting the pricing of its public offering of common stock.
The Company filed a Current Report on Form 8-K dated October
23, 1997 reporting the consumation of its public offering of common
stock and the concurrent sale of 2 million shares of common stock in a
direct sale.
The Company filed a Current Report on Form 8-K dated October
28, 1997 reporting the closing of the sale of $350 million aggregate
principal amount of its 7.63% senior notes due 2007.
The Company filed a Current Report on Form 8-K dated December
5, 1997 reporting that its indirect subsidiary, CE Electric UK Funding
Company had arranged for the sale of $362 million Senior Notes and 200
million pounds Sterling Bonds.
The Company filed a Current Report on Form 8-K dated December
11, 1997 reporting the increase in the authorized purchase amounts
under its stock repurchase program.
The Company filed a Current Report on Form 8-K dated December
16, 1997 reporting the closing of the sale of $125 million of its
6.853% Senior Notes due 2004, $237 million of its 6.995% Senior Notes
due 2007 and 200 million pounds of its 7.25% Sterling Bonds due 2022.
(c) Exhibits
The exhibits listed on the accompanying Exhibit Index (except
in the case of Exhibit 13.0, in which case only the portion of the
Annual Report which constitutes the Company's Consolidated Financial
Statements and notes thereto) are filed as part of this Annual Report.
For the purposes of complying with the amendments to the
rules governing Form S-8 effective July 13, 1990 under the Securities
Act of 1933, the undersigned Registrant hereby undertakes as follows,
which undertaking shall be incorporated by reference into the Company's
currently effective Registration Statements on Form S-8:
Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and
controlling persons of the registrant, the registrant has been advised
that in the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the Securities
Act of 1933 and is, therefore, unenforceable. In the event that a claim
for indemnification against such liabilities (other than the payment by
the registrant of expenses incurred or paid by a director, officer of
controlling person of the registrant in the successful defense of any
action, suit or proceeding) is asserted by such director, officer or
controlling person in connection with the securities being registered,
the registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of
appropriate jurisdiction the question of whether such indemnification
by it is against public policy as expressed in the Act and will be
governed by the final adjudication of such issue.
(d) Financial statements required by Regulations S-X, which are
excluded from the Annual Report by Rule 14a-3(b).
The consolidated financial statements of Magma Company and
subsidiaries (financial statements of affiliates whose securities are
pledged as collateral) are filed as part of this report immediately
following Schedule I.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned thereunto duly authorized, in
the City of Omaha, State of Nebraska, on this 27th day of March, 1998.
CALENERGY COMPANY, INC.
/s/ David L. Sokol*
By David L. Sokol
Chairman of the Board and Chief
Executive Officer
*By: /s/ Steven A. McArthur
Steven A. McArthur
Attorney-in-Fact
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
Signature
Date
/s/ David L. Sokol* March 27, 1998
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and
Director
/s/ Gregory E. Abel* March 27, 1998
Gregory E. Abel
President and Chief Operating Officer
/s/ Craig M. Hammett March 27, 1998
Craig M. Hammett
Senior Vice President,
Chief Financial Officer
/s/ Patrick J. Goodman March 27, 1998
Patrick J. Goodman
Vice President,
Chief Accounting Officer
and Controller
/s/ Edgar D. Aronson* March 27, 1998
Edgar D. Aronson
Director
*By:/s/ Steven A. McArthur March 27, 1998
Steven A. McArthur
Attorney-in-Fact
/s/ Judith E. Ayres* March 27, 1998
Judith E. Ayres
Director
/s/ Richard K. Davidson* March 27, 1998
Richard K. Davidson
Director
/s/ David H. Dewhurst* March 27, 1998
David H. Dewhurst
Director
/s/ Richard R. Jaros* March 27, 1998
Richard R. Jaros
Director
/s/ David R. Morris* March 27, 1998
David Morris
Director
/s/ John R. Shiner* March 27, 1998
John R. Shiner
Director
/s/ Bernard W. Reznicek* March 27, 1998
Bernard W. Reznicek
Director
/s/ Walter Scott, Jr.* March 27, 1998
Walter Scott, Jr.
Director
/s/ David E. Wit* March 27, 1998
David E. Wit
Director
*By:/s/ Steven A. McArthur March 27, 1998
Steven A. McArthur
Attorney-in-Fact
CalEnergy Company, Inc. Schedule I
Parent Company Only
Condensed Balance Sheets
as of December 31, 1997 and 1996
(dollars and shares in thousands, except per share amounts)
ASSETS 1997 1996
Cash and cash equivalents $ 1,280,477$ 68,449
Restricted cash 114,492 21,208
Short-term investment 421 192
Investments in and advances to
subsidiaries and joint ventures 1,793,413 1,952,612
Equipment, net 19,016 9,797
Notes receivable - joint ventures --- 27,375
Deferred income taxes 25,007 ---
Deferred charges and other assets 104,802 90,234
Total assets $ 3,337,628 $2,169,867
LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable and other accrued
liabilities $ 46,964 $ 12,999
Parent company debt 1,303,845 1,146,685
Deferred income taxes --- 12,688
Total liabilities 1,350,809 1,172,372
Deferred income 12,827 12,775
Company-obligated mandatorily redeemable
convertible preferred securities of
subsidiary trusts 553,930 103,930
Common stock and options subject
to redemption 654,736 ---
Stockholders' equity:
Preferred stock - authorized 2,000 shares --- ---
Common stock - par value $0.0675 per share,
authorized 180,000 shares, issued 82,980
and 63,747 shares,outstanding 81,322 and
63,448 shares, respectively 5,602 4,303
Additional paid in capital 1,261,081 563,567
Retained earnings 213,493 297,520
Cumulative effect of foreign currency
translation adjustment (3,589) 29,658
Common stock and options subject to
redemption (654,736) ---
Treasury stock-1,658 and 299 common
shares at cost (56,525) (8,787)
Unearned compensation - restricted stock --- (5,471)
Total stockholders' equity 765,326 880,790
Total liabilities and stockholders'
equity $3,337,628 $2,169,867
The notes to the consolidated CalEnergy financial statements are an
integral part of these financial statements.
CalEnergy Company, Inc. Schedule I
Parent Company Only (continued)
Condensed Statements Of Operations
for the three years ended December 31, 1997
(dollars in thousands)
1997 1996 1995
Revenue:
Equity in undistributed earnings of
subsidiary companies and joint ventures $ 87,006 $ 91,528 $52,960
Cash dividends and distributions from
subsidiary companies and joint ventures 156,686 102,428 88,360
Interest and other income 49,488 22,459 16,065
Total revenues 293,180 216,415 157,385
Expenses:
General and administration 51,519 22,958 16,354
Interest, net of capitalized interest 67,636 54,484 46,985
Total expenses 119,155 77,442 63,339
Income before provision for income taxes 174,025 138,973 94,046
Provision for income taxes 99,044 41,821 30,631
Income before minority interest 74,981 97,152 63,415
Minority interest 23,158 4,691 ---
Income before extraordinary item 51,823 92,461 63,415
Extraordinary item, net of minority
interest of $58,222 (135,850) --- ---
Net income (loss) (84,027) 92,461 63,415
Preferred dividends --- --- 1,080
Net income (loss) available to common
stockholders $(84,027) $92,461 $62,335
Income per share before extraordinary
item $ .77 $ 1.69 $ 1.32
Extraordinary item $ (2.02) $ --- $ ---
Net income (loss) per share $ (1.25) $ 1.69 $ 1.32
Income per share before extraordinary
item - diluted $ .75 $ 1.54 $ 1.22
Extraordinary item-diluted $ (1.97) $ --- $ ---
Net income (loss) per share-diluted $ (1.22) $ 1.54 $ 1.22
Average number of shares outstanding 67,268 54,739 47,249
Diluted shares 68,686 65,072 56,195
The notes to the consolidated CalEnergy financial statements are an
integral part of these financial statements.
CalEnergy Company, Inc. Schedule I
Parent Company Only (continued)
Condensed Statements Of Cash Flows
for the three years ended December 31, 1997
(dollars in thousands)
1997 1996 1995
Cash flows from operating activities $(237,752) $(51,621) $(33,469)
Cash flows from investing activities:
Decrease (increase) in advances to and
investments in subsidiaries and joint
ventures 305,563 (531,410) (747,516)
Decrease (increase) in short-term investments (229) 33,998 15,810
Decrease (increase) in restricted cash (93,284) 19,423 50,274
Other 18,330 (5,179) 10,699
Cash flows from investing activities 230,380 (483,168) (670,733)
Cash flows from financing activities:
Proceeds from sale of common and treasury
stock and exercise of stock options 703,624 54,935 299,649
Proceeds from issuance of parent company debt 350,000 324,150 200,000
Proceeds from convertible preferred securities
of subsidiary trusts 450,000 103,930 ---
Repayment of parent company debt (100,000) --- ---
Net proceeds from revolver (95,000) 95,000 ---
Purchase of treasury stock (55,505) (12,008) (1,590)
Deferred charges relating to debt financing (33,719) (8,811) ---
Cash flows from financing activities 1,219,400 557,196 498,059
Net increase (decrease) in cash and cash
equivalents 1,212,028 22,407 (206,143)
Cash and cash equivalents at beginning
of period 68,449 46,042 252,185
Cash and cash equivalents at end of period $1,280,477 $ 68,449 $ 46,042
Supplemental disclosures:
Interest paid (net of amount capitalized) $ 38,176 $ 1,705 $ 5,172
Income taxes paid $ 35,302 $ 23,211 $ 14,812
The notes to the consolidated CalEnergy financial statements are an
integral part of these financial statements.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders
CalEnergy Company, Inc.
Omaha, Nebraska
We have audited the consolidated financial statements of CalEnergy
Company, Inc. and subsidiaries as of December 31, 1997 and 1996, and
for each of the three years in the period ended December 31, 1997, and
have issued our report thereon dated February 12, 1998; such financial
statements and reports are included in your 1997 Annual Report to
Stockholders and are incorporated herein by reference. Our audits also
included the financial statement schedule of CalEnergy Company, Inc.
and subsidiaries, listed in Item 14. This financial statement schedule
is the responsibility of the Company's management. Our responsibility
is to express an opinion based on our audits. In our opinion, such
financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.
Deloitte & Touche, LLP
Omaha, Nebraska
February 12, 1998
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
INDEX TO FINANCIAL STATEMENTS
The following consolidated financial statements of Magma Power Company
and the related independent accountants' reports are included in Items
14(d):
Independent Auditors' Report--Deloitte & Touche LLP F-2
Consolidated balance sheets at December 31, 1997 and 1996 F-3
Consolidated statements of operations for the three years
ended December 31, 1997 F-4
Consolidated statements of stockholder's equity for the three
years ended December 31, 1997 F-5
Consolidated statements of cash flows for the three years
ended December 31, 1997 F-6
Notes to consolidated financial statements F-7
All schedules have been omitted because they are not applicable or not
required, or because the required information is shown in the
consolidated financial statements or notes thereto.
INDEPENDENT AUDITORS' REPORT
Board of Directors and Shareholder
Magma Power Company
Omaha, Nebraska
We have audited the accompanying consolidated balance sheets of Magma
Power Company and subsidiaries, a wholly-owned subsidiary of CalEnergy
Company, Inc., as of December 31, 1997 and 1996 the related
consolidated statements of operations, stockholder's equity and cash
flows for the years then ended. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of Magma Power Company
and subsidiaries at December 31, 1997 and 1996 and the results of their
operations and their cash flows for the years then ended in conformity
with generally accepted accounting principles.
Deloitte & Touche LLP
Omaha, Nebraska
February 12, 1998
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
CONSOLIDATED BALANCE SHEETS
as of December 31, 1997 and 1996
dollars and shares in thousands except per share amounts
ASSETS 1997 1996
Cash and cash equivalents $ 14,051 $ 13,429
Restricted cash 51,835 23,695
Accounts receivable 57,411 44,966
Due from parent 80,924 68,694
Properties, plants, contracts and
equipment, net 1,207,605 1,225,684
Excess of cost over fair value of net
assets acquired, net 291,303 299,055
Deferred charges and other assets 69,788 62,874
Total assets $1,772,917 $1,738,397
LIABILITIES AND STOCKHOLDER'S EQUITY
Liabilities:
Accounts payable and other accrued
liabilities $ 32,773 $ 52,281
Construction and project loans 176,657 137,881
Salton Sea notes and bonds 448,754 538,982
Limited recourse senior secured notes 200,000 200,000
Deferred income taxes 228,246 210,969
Total liabilities 1,086,430 1,140,113
Deferred income 12,396 ---
Commitments and contingencies (Note 9)
Stockholder's equity:
Preferred stock - par value $0.10 per share,
authorized 1,000 shares --- ---
Common stock - par value $0.10 per share,
authorized 30,000 shares, outstanding
100 shares --- ---
Additional paid in capital 501,626 501,626
Retained earnings 172,465 96,658
Total stockholder's equity 674,091 598,284
Total liabilities and stockholder's equity$1,772,917 $1,738,397
The accompanying notes are an integral part of these financial
statements.
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
CONSOLIDATED STATEMENTS OF OPERATIONS
for the three years ended December 31, 1997
dollars in thousands
1997 1996 1995
Revenue:
Sales of electricity and steam $ 328,248 $ 249,293 $ 162,418
Royalty income 3,489 6,846 19,962
Interest and other income 3,978 9,368 17,812
Total revenues 335,715 265,507 200,192
Cost and expenses:
Plant operations 72,196 67,350 57,782
General and administration 1,380 503 3,282
Depreciation and amortization 89,134 69,853 46,895
Interest expense 72,386 67,652 60,596
Less interest capitalized (20,549) (27,382) (24,568)
Total expenses 214,547 177,976 143,987
Income before provision for income
taxes and minority interest 121,168 87,531 56,205
Provision for income taxes 45,361 25,489 17,498
Income before minority interest 75,807 62,042 38,707
Minority interest --- --- 4,091
Net income $75,807 $62,042 $34,616
The accompanying notes are an integral part of these financial
statements.
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
for the three years ended December 31, 1997
dollars and shares in thousands
Outstanding Additional
Common Common Paid-In Retained
Shares Stock Capital Earnings Total
Balance, January 1, 1995 24,117 $ 2,411 $ 144,916 $ 242,489 $ 389,816
Net income in 1995 prior to
acquisition --- --- --- 4,091 4,091
Purchase accounting push-down
adjustments, net (24,049) (2,415) 332,857 (246,580) 83,862
Contributions from parent --- --- 22,947 --- 22,947
Other equity transactions, net 32 4 906 --- 910
Net income --- --- --- 34,616 34,616
Balance, December 31, 1995 100 --- 501,626 34,616 536,242
Net income --- --- --- 62,042 62,042
Balance, December 31, 1996 100 --- 501,626 96,658 598,284
Net income --- --- --- 75,807 75,807
Balance, December 31, 1997 100 $ --- $501,626 $ 172,465 $ 674,091
The accompanying notes are an integral part of these financial statements.
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the three years ended December 31, 1997
Dollars in thousands
1997 1996 1995
Cash flows from operating activities:
Net income $ 75,807$ 62,042 $ 34,616
Adjustments to reconcile net cash flows from operating activities:
Minority interest --- --- 4,091
Provision for deferred income taxes 17,277 7,277 7,614
Depreciation and amortization 89,134 69,853 46,895
Changes in other items:
Accounts receivable (12,445) (7,735) 4,354
Accounts payable and other accrued liabilities (19,508) 3,325 14,153
Net cash flows from operating activities 150,265 134,762 111,723
Cash flows from investing activities:
Capital expenditures (50,907)(190,152) (171,063)
Purchase of Partnership Interest, net of
cash acquired --- (58,044) ---
Purchase of Magma, net of cash acquired --- --- (907,614)
Decrease (increase) in restricted cash (28,140) 59,071 (4,785)
Increase in other assets (6,914) (3,345) (24,037)
Net cash flows from investing activities (85,961)(192,470)(1,107,499)
Cash flows from financing activities:
Due from parent (12,230) (53,203) (29,669)
Proceeds from debt offerings --- 135,000 675,000
Repayment of Salton Sea notes and bonds (90,228) (48,106) (22,912)
Repayment of project loans --- (102,999) (124,839)
Proceeds from construction and other loans 38,776 101,018 36,863
Other equity transactions, net --- --- 910
Advances from parent --- --- 499,850
Net cash flows from financing activities (63,682) 31,710 1,035,203
Net increase (decrease) in cash and cash
equivalents 622 (25,998) 39,427
Cash and cash equivalents at beginning of period 13,429 39,427 ---
Cash and cash equivalents at end of period $ 14,051 $ 13,429 $ 39,427
Interest paid (net of amounts capitalized) $ 50,802 $ 49,129 $ 50,840
Income taxes paid $ --- $ --- $ 14,812
The accompanying notes are an integral part of these financial
statements.
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CalEnergy Company, Inc.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
for the three years ended December 31, 1997
dollars and shares in thousands
1. BUSINESS
Magma Power Company (the "Company" or "Magma"), a wholly-owned
subsidiary of CalEnergy Company, Inc. (CalEnergy), is primarily engaged
in the exploration for and development of geothermal resources and
conversion of such resources into electrical power and steam for sale
to electric utilities, and the development of other environmentally
responsible forms of power generation.
The Company currently operates eight geothermal power plants in the
Imperial Valley in California. On April 17, 1996 the Company completed
the acquisition of Edison Mission Energy's partnership interests (the
"Partnership Interest Acquisition") in four geothermal operating
facilities in California for a cash purchase price of $71,000 including
acquisition costs. The four projects, Vulcan, Hoch (Del Ranch),
Leathers and Elmore are located in the Imperial Valley of California.
Prior to this transaction, the Company was a 50% owner of these
facilities. The remaining four plants are the Salton Sea Project which
are wholly-owned by subsidiaries of the Company. These geothermal
power plants consist of the Salton Sea I, Salton Sea II, Salton Sea
III, and Salton Sea IV. The Salton Sea IV project commenced operations
in June 1996.
In 1995 the Company, through its wholly-owned subsidiary, Visayas
Geothermal Power Company ("VGPC"), began construction of the Malitbog
Geothermal Project on the island of Leyte in the Republic of the
Philippines. Unit I was deemed complete on July 25, 1996. Units II and
III were deemed complete on July 25, 1997.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries. Prior to the Partnership
Interest Acquisition, the consolidated financial statements include the
Company's proportionate share of the joint ventures in which it had an
undivided interest in the assets and was proportionately liable for its
share of liabilities. All significant inter-enterprise transactions
and accounts have been eliminated. The results of operations of the
Company include the Company's proportionate share of the results of
operations of entities acquired as of the date of acquisition.
The consolidated financial statements reflect the acquisition by
CalEnergy and the resulting push down to the Company of the accounting
as a purchase business combination.
Restricted Cash
The restricted cash balance is mainly composed of restricted accounts
for debt service reserve funds and a capital expenditure fund. The
debt service reserve funds are legally restricted to their use and
require the maintenance of specific minimum balances.
Well, Resource Development and Exploration Costs
The Company follows the full cost method of accounting for costs
incurred in connection with the exploration and development of
geothermal resources. All such costs, which include dry hole costs and
the cost of drilling and equipping production wells and directly
attributable administrative and interest costs, are capitalized and
amortized over their estimated useful lives when production commences.
The estimated useful lives of production wells are ten to twenty years
depending on the 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.
Deferred Well and Rework Costs
Well rework costs are deferred and amortized over the estimated period
between reworks. These deferred costs, net of accumulated
amortization, are $4,811 and $7,664 at December 31, 1997 and 1996,
respectively, and are included in other assets.
Properties, Plants, Contracts, Equipment and Depreciation
The cost of major additions and betterments are capitalized, while
replacements, maintenance, and repairs that do not improve or extend
the lives of the respective assets are expensed.
Depreciation of the operating power plant costs, net of salvage value,
is computed on the straight line method over the estimated useful
lives, between 10 and 30 years. Depreciation of furniture, fixtures
and equipment, which are recorded at cost, is computed on the straight
line method over the estimated useful lives of the related assets,
which range from three to ten years.
The Magma and Partnership Interest Acquisitions by the Company have
been accounted for as purchase business combinations. All identifiable
assets acquired and liabilities assumed were assigned a portion of the
cost of acquiring the respective companies, equal to their fair values
at the date of the acquisition and include the following:
Power sales agreements are amortized separately over (1) the
remaining portion of the scheduled price periods of the power
sales agreements and (2) the 20 year avoided cost periods of the
power sales agreements using the straight line method.
The carrying value of the mineral reserves will be amortized upon
commencement of commercial operation.
Excess of Cost over Fair Value
Total acquisition costs in excess of the fair values assigned to the
net assets acquired are amortized over a 40 year period using the
straight line method.
Capitalization of Interest and Deferred Financing Costs
Prior to the commencement of operations, interest is capitalized on the
costs of the plants and geothermal resource development to the extent
incurred. Capitalized interest and other deferred charges are
amortized over the lives of the related assets.
Deferred financing costs are amortized over the term of the related
financing using the effective interest method.
Revenue Recognition
Revenues are recorded based upon service rendered and electricity and
steam delivered to the end of the month. See Note 4 for contractual
terms of power sales agreements. Royalties earned from providing
geothermal resources to power plants operated by other geothermal power
producers are recorded on an accrual basis. Prior to the Partnership
Interest Acquisition, royalties contractually payable to the Company by
the Partnership Project were recorded on an accrual basis, net of the
Company's 50% share of the corresponding partnership project expense.
All intercompany royalties were eliminated after the acquisition of the
remaining 50% partnership interest.
Income Taxes
The Company is included in the consolidated income tax returns of
CalEnergy and affiliates. The provision for income taxes is computed
on a separate return basis. The Company recognizes deferred tax assets
and liabilities based on the difference between the financial statement
and tax bases of assets and liabilities using estimated tax rates in
effect for the year in which the differences are expected to reverse.
Fair Values of Financial Instruments
The following methods and assumptions were used by the Company in
estimating fair values of financial instruments as discussed herein.
Fair values have been estimated based on quoted market prices for debt
issues listed on exchanges. Fair values of financial instruments that
are not actively traded are based on market prices of similar
instruments and/or valuation techniques using market assumptions.
Cash Equivalents
The Company considers all investment instruments purchased with an
original maturity of three months or less to be cash equivalents.
Restricted cash is not considered a cash equivalent.
Impairment of Long-Lived Assets
The Company reviews long-lived assets and certain identifiable
intangibles be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. An impairment loss would be recognized whenever evidence
exists that the carrying value is not recoverable.
Reclassification
Certain amounts in the fiscal 1996 and 1995 financial statements and
supporting footnote disclosures have been reclassified to conform to
the fiscal 1997 presentation. Such reclassification did not impact
previously reported net income or retained earnings.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ
from those estimates.
3. ACQUISITIONS
Magma Power Company
On January 10, 1995, CalEnergy acquired approximately 51% of the
outstanding shares of common stock of the Company through a cash tender
offer and completed the acquisition on February 24, 1995 by acquiring
the remaining 49% of outstanding shares of common stock through a
merger (the "Magma Acquisition").
The Magma Acquisition has been accounted for as a purchase business
combination. All identifiable assets acquired and liabilities assumed
were assigned a portion of the cost of acquiring Magma, equal to their
fair values at the date
of the acquisition.
Edison Mission Energy's Partnership Interest
On April 17, 1996 the Company completed the acquisition of Edison
Mission Energy's partnership interests (the "Partnership Interest
Acquisition") in four geothermal operating facilities in California for
a cash purchase price of $71,000 including acquisition costs. The four
projects, Vulcan, Hoch (Del Ranch), Leathers and Elmore are located in
the Imperial Valley of California. Prior to this transaction, the
Company was a 50% owner of these facilities.
The Partnership Interest Acquisition has been accounted for as a
purchase business combination. All identifiable assets acquired and
liabilities assumed were assigned a portion of the cost of acquiring
the Partnership Interest, equal to their fair values at the date of the
acquisition.
Unaudited pro forma combined revenue and net income of the Company and
the Partnership Interest for the twelve months ended December 31, 1996
and 1995, as if the acquisition had occurred at the beginning of 1995
after giving effect to certain pro forma adjustments related to the
acquisition were $284,193 and $63,135 compared to $291,812 and $52,477,
respectively.
4. PROPERTIES, PLANTS, CONTRACTS AND EQUIPMENT
Properties, plants, contracts and equipment comprise the following at
December 31:
1997 1996
Power plants $741,853 $557,006
Wells and resource development 124,500 114,492
Power sales agreements 264,371 264,371
Licenses and equipment 46,290 46,290
Total operating facilities 1,177,014 982,159
Less accumulated depreciation
and amortization (185,085) (103,702)
Net operating facilities 991,929 878,457
Mineral reserves 211,674 189,198
Construction in progress:
Malitbog --- 155,410
Other development 4,002 2,619
Total $1,207,605 $1,225,684
Imperial Valley Project Operating Facilities
The Partnership Project and the Salton Sea Project are collectively
referred to as the Imperial Valley Project. The Imperial Valley
Project commencement dates and nominal capacities are as follows:
Imperial Valley Commencement Nominal
Plants Date Capacity
Vulcan February 10, 1986 34 MW
Del Ranch January 2, 1989 38 MW
Elmore January 1, 1989 38 MW
Leathers January 1, 1990 38 MW
Salton Sea I July 1, 1987 10 MW
Salton Sea II April 5, 1990 20 MW
Salton Sea III February 13, 1989 49.8 MW
Salton Sea IV May 24, 1996 39.6 MW
Significant Customers and Contracts
All of the Company's sales of electricity from the Imperial Valley
Project, which comprise approximately 82% of 1997 electricity and steam
revenues, are to Southern California Edison Company ("Edison") and are
under long-term power purchase contracts.
The Partnership Project sells all electricity generated by the
respective plants pursuant to four long-term SO4 Agreements between the
project and Edison. These SO4 Agreements provide for capacity
payments, capacity bonus payments and energy payments. Edison makes
fixed annual capacity and capacity bonus payments to the projects to
the extent that capacity factors exceed certain benchmarks. The price
for capacity and capacity bonus payments is fixed for the life of the
SO4 Agreements. Energy is sold at increasing scheduled rates for the
first ten years after firm operation and thereafter at Edison's Avoided
Cost of Energy.
The scheduled energy price periods of the Partnership Project SO4
Agreements extended until February 1996 for the Vulcan Partnership and
extend until December 1998, December 1998, and December 1999 for each
of the Del Ranch, Elmore and Leathers Partnerships, respectively.
Excluding Vulcan, which is receiving Edison's Avoided Cost of Energy,
the Company's SO4 Agreements provide for energy rates ranging from 13.6
cents per kWh in 1997 to 15.6 cents per kWh in 1999. The weighted
average energy rate for all of the Company's SO4 Agreements was 10.0
cents per kWh in 1997.
Salton Sea I sells electricity to Edison pursuant to a 30-year
negotiated power purchase agreement, as amended (the "Salton Sea I
PPA"), which provides for capacity and energy payments. The energy
payment is calculated using a Base Price which is subject to quarterly
adjustments based on a basket of indices. The time period weighted
average energy payment for Salton Sea I was 5.3 cents per kWh during
1997. As the Salton Sea I PPA is not an SO4 Agreement, the energy
payments do not revert to Edison's Avoided Cost of Energy. The
capacity payment is approximately $1,100 per annum.
Salton Sea II and Salton Sea III sell electricity to Edison pursuant to
30-year modified SO4 Agreements that provide for capacity payments,
capacity bonus payments and energy payments. The price for contract
capacity and contract capacity bonus payments is fixed for the life of
the modified SO4 Agreements. The energy payments for the first ten
year period, which period expires in April 2000 and February 1999 are
levelized at a time period weighted average of 10.64 per kWh and 9.84
per kWh for Salton Sea II and Salton Sea III, respectively.
Thereafter, the monthly energy payments will be Edison's Avoided Cost
of Energy. For Salton Sea II only, Edison is entitled to receive, at
no cost, 5% of all energy delivered in excess of 80% of contract
capacity through September 30, 2004. The annual capacity and bonus
payments for Salton Sea II and Salton Sea III are approximately $3,300
and $9,700, respectively.
Salton Sea IV sells electricity to Edison pursuant to a modified SO4
agreement which provides for contract capacity payments on 34 MW of
capacity at two different rates based on the respective contract
capacities deemed attributable to the original Salton Sea PPA option
(20 MW) and to the original Fish Lake PPA (14 MW). The capacity
payment price for the 20 MW portion adjusts quarterly based upon
specified indices and the capacity payment price for the 14 MW portion
is a fixed levelized rate. The energy payment (for deliveries up to a
rate of 39.6 MW) is at a fixed price for 55.6% of the total energy
delivered by Salton Sea IV and is based on an energy payment schedule
for 44.4% of the total energy delivered by Salton Sea IV. The contract
has a 30-year term but Edison is not required to purchase the 20 MW of
capacity and energy originally attributable to the Salton Sea I PPA
option after September 30, 2017, the original termination date of the
Salton Sea I PPA.
For the year ended December 31, 1997 and 1996, Edison's average Avoided
Cost of Energy was 3.3 cents and 2.5 cents per kWh, respectively, which
is substantially below the contract energy prices earned for the year
ended December 31, 1997. Estimates of Edison's future Avoided Cost of
Energy vary substantially from year to year. The Company cannot
predict the likely level of Avoided Cost of Energy prices under the SO4
Agreements and the modified SO4 Agreements at the expiration of the
scheduled payment periods. The revenues generated by each of the
projects operating under SO4 Agreements could decline significantly
after the expiration of the respective scheduled payment periods.
Subsidiaries of Magma sought new long-term final SO4 power purchase
agreements in the Salton Sea area through the bidding process adopted
by the California Public Utilities Commission ("CPUC") under its 1992
Biennial Resource Plan Update ("BRPU"). In its BRPU, the CPUC cited
the need for an additional 9,600 MW of power production through 1999
among California's three investor-owned utilities, Edison, San Diego
Gas and Electric ("SDG&E") and Pacific Gas and Electric Company. Of
this amount, 275 MW was set aside for bidding by independent power
producers (such as Magma) utilizing renewable resources. Pursuant to
an order of the CPUC dated June 22, 1994 (confirmed on December 21,
1994), Magma was awarded 163 net MW for sale to Edison and SDG&E, with
in-service dates in 1997 and 1998. On February 23, 1995 the Federal
Energy Regulatory Commission ("FERC") issued an order finding that the
CPUC's BRPU program violated the Public Utilities Regulatory Policies
Act ("PURPA") and FERC's implementing regulations and recommended
negotiated settlements. In response, the CPUC issued an Assigned
Commissioners Ruling encouraging settlements between the final winning
bidders and the utilities. The utilities are expected to continue to
challenge the BRPU and, in the light of the regulatory uncertainty,
there can be no assurance that power sales contracts will be executed
or that any such projects will be completed. In light of these
developments, the Company agreed to execute an agreement with Edison on
March 16, 1995 providing that in certain circumstances it would
withdraw its Edison BRPU bid in consideration for the payment of
certain sums. In December, 1996, the Company entered into a
confidential cash buyout agreement with SDG&E. These agreements are
subject to CPUC approval.
Unit I of the Malitbog Project was deemed complete in July 1996 and
Units II and III in July 1997 at which times such units commenced
receiving capacity payments under the Malitbog Energy Conversion
Agreement ("ECA"). The Malitbog Project is owned and operated by VGPC,
a Philippine general partnership that is wholly owned, indirectly, by
the Company. The Malitbog Project is structured as a ten year Build-
Own-Operate-Transfer ("BOOT") project, in which the Company is
responsible for providing operations and maintenance for the ten year
BOOT period. The electricity generated by the Malitbog Project is sold
to PNOC-Energy Development Corporation ("PNOC-EDC"), which will in turn
sell the power to the National Power Corporation of the Philippines
("NPC"). After a ten year cooperation period, and the recovery by the
Company of its capital investment plus incremental return, the plant
will be transferred to PNOC-EDC at no cost.
PNOC-EDC is obligated to pay for electric capacity that is nominated
each year by VGPC, irrespective of whether PNOC-EDC is willing or able
to accept delivery of such capacity. VGPC receives 100% of its
revenues from such sales in the form of capacity payments. Payments
under the Malitbog ECA are denominated in U.S. Dollars, or computed in
U.S. dollars and paid in Philippine pesos at the then-current exchange
rate. Significant portions of the capacity fee are indexed to U.S. and
Philippine inflation rates, respectively. PNOC-EDC's payment
requirements, and its other obligations under the Malitbog ECA are
supported by the Government of the Philippines through a performance
undertaking.
Royalties
Royalty expense for the years ended December 31, 1997, 1996 and 1995,
which is included in plant operations in the consolidated statements of
operations, comprise the following:
1997 1996 1995
Vulcan $ 326 $ 361 $ 1,207
Leathers 2,694 2,203 1,968
Elmore 2,213 1,883 1,713
Del Ranch 2,650 2,255 1,932
Salton Sea I & II 1,206 634 1,147
Salton Sea III 2,439 1,334 2,431
Salton Sea IV 2,815 1,558 -
Total $14,343 $10,228 $10,398
The Partnership Project pays royalties based on both energy revenues
and total electricity revenues. Hoch (Del Ranch) and Leathers pay
royalties of approximately 5% of energy revenues and 1% of total
electricity revenue. Elmore pays royalties of approximately 5% of
energy revenues. Vulcan pays royalties of 4.167% of energy revenues.
The Salton Sea Project's weighted average royalty expense in 1997 was
approximately 6.1%. The royalties are paid to numerous recipients
based on varying percentages of electrical revenue or steam production
multiplied by published indices.
5. CONSTRUCTION LOANS
Draws on the construction loan for the Malitbog geothermal power
project at December 31, 1997 totaled $176,657. International banks and
the Overseas Private Investment Corporation ("OPIC") have provided the
construction and term loan facilities at variable interest rates
(weighted average of 8.48% and 8.15% at December 31, 1997 and 1996,
respectively). The international bank portion of the debt will be
insured by OPIC against political risks and the Company's equity
contribution to VGPC is covered by political risk insurance from the
Multilateral Investment Guarantee Agency and OPIC. The construction
loan is expected to be converted to a term loan promptly after NPC
completes the full capacity transmission line, which is currently
expected in 1998.
6. NOTES AND BONDS
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 the Imperial Valley and Malitbog projects or (2) owning
interests in the subsidiaries that own interests in the foregoing
projects.
Salton Sea Notes and Bonds
The Salton Sea Funding Corporation, a wholly owned subsidiary of the
Company, (the "Funding Corporation") debt securities are as follows:
Final
Maturity December 31, December 31,
Senior Secured Series Date Rate 1997 1996
July 21, 1995 A Notes May 30, 2000 6.69% $ 97,354 $ 161,732
July 21, 1995 B Bonds May 30, 2005 7.37% 133,000 133,000
July 21, 1995 C Bonds May 30, 2010 7.84% 109,250 109,250
June 20, 1996 D Notes May 30, 2000 7.02% 44,150 70,000
June 20, 1996 E Bonds May 30, 2011 8.30% 65,000 65,000
$448,754 $538,982
Principal and interest payments are made in semi-annual installments.
The Salton Sea Notes and Bonds are secured by the Company's four
existing Salton Sea plants as well as an assignment of the right to
receive various royalties payable to Magma in connection with its
Imperial Valley properties and distributions from the Partnership
Project. The Salton Sea Notes and Bonds are nonrecourse to CalEnergy.
Pursuant to a depository agreement, Funding Corporation established a
debt service reserve fund in the form of a letter of credit in the
amount of $70,430 from which scheduled interest and principal payments
can be made.
Annual repayments of the Salton Sea Notes and Bonds for the years
beginning January 1, 1998 and thereafter are as follows:
1998 $106,938
1999 57,836
2000 25,072
2001 22,376
2002 24,298
Thereafter 212,234
$448,754
On July 21, 1995, CalEnergy issued $200,000 of 9 7/8% Limited Recourse
Senior Secured Notes Due 2003 (the "Notes"). Interest on the Notes is
payable on June 30 and December 30 of each year, commencing December
1995. The Notes are secured by an assignment and pledge of 100% of the
outstanding capital stock of Magma and are recourse only to such Magma
capital stock, CalEnergy's interest in a secured Magma note and general
assets of CalEnergy equal to the Restricted Payment Recourse Amount (as
defined in the Note Indenture) which was $0 at December 31, 1997.
At any time or from time to time on or prior to June 30, 1998,
CalEnergy may, at its option, use all or a portion of the net cash
proceeds of a CalEnergy equity offering (as defined in the Note
Indenture) and shall at any time use all of the net cash proceeds of
any Magma equity offering (as defined in the Note Indenture) to redeem
up to an aggregate of 35% of the principal amount of the Notes
originally issued at a redemption price equal to 109.875% of the
principal amount thereof plus accrued interest to the redemption date.
On or after June 30, 2000, the Notes are redeemable at the option of
the CalEnergy, in whole or in part, initially at a redemption price of
104.9375% declining to 100% on June 30, 2002 and thereafter, plus
accrued interest to the date of redemption.
7. INCOME TAXES
Provision for income tax is comprised of the following at December 31:
1997 1996 1995
Currently payable:
State $ 7,488 $ 6,420 $ 2,228
Federal 20,596 11,792 7,656
28,084 18,212 9,884
Deferred:
State 1,342 1,232 924
Federal 15,207 4,908 6,690
Foreign 728 1,137 ---
17,277 7,277 7,614
Total $45,361 $25,489 $17,498
The deferred expense is primarily temporary differences associated with
depreciation and amortization of certain assets.
A reconciliation of the federal statutory tax rate to the effective tax
rate applicable to income before provision for income taxes follows:
1997 1996 1995
Federal statutory rate 35.00% 35.00% 35.00%
Percentage depletion in
excess of cost depletion (4.30) (5.15) (6.44)
Investment and energy
tax credits (.84) (12.30) (2.05)
State taxes, net of federal
tax effect 4.74 4.26 4.34
Goodwill amortization 2.24 3.10 4.99
Tax effect of foreign income .60 1.30 ---
Lease investment --- --- (3.88)
Other --- 2.91 (.83)
37.44% 29.12% 31.13%
Deferred tax liabilities (assets) are comprised of the following at
December 31:
1997 1996
Depreciation and amortization, net $249,622 $249,453
Unremitted foreign earnings 14,112 ---
Other 77 788
263,811 250,241
Accruals not currently deductible for
tax purposes (2,304) ---
Tax credits (19,692) (33,407)
Jr. SO4 royalty receivable (5,865) (5,865)
Deferred income (7,588) ---
Other (116) ---
(35,565) (39,272)
Net deferred taxes $228,246 $210,969
8. FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of a financial instrument is the amount at which the
instrument could be exchanged in a current transaction between willing
parties, other than in a forced sale or liquidation. Although
management uses its best judgment in estimating the fair value of these
financial instruments, there are inherent limitations in any estimation
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.
Other financial instruments - All other financial instruments of a
material nature fall into the definition of short-term and fair value
is estimated as the carrying amount.
The carrying amounts in the table below are included in the
consolidated balance sheets under the indicated captions.
1997 1996
Estimated Estimated
Carrying Fair Carrying Fair
Value Value Value Value
Construction and project loans 176,657 176,657 137,881 137,881
Salton Sea notes and bonds 448,754 463,720 538,982 531,807
Limited recourse senior
secured notes 200,000 217,829 200,000 212,560
9. LITIGATION
As of December 31, 1997 there were no material outstanding lawsuits.
EXHIBIT INDEX
3.1 The Company's Restated Certificate of Incorporation (incorporated
by reference to Exhibit 3.1 of the Company's Form 10-K for the
year ended December 31, 1992, File No. 1-9874 (the "1992 Form 10-
K")).
3.2 Certificate of Amendment of the Company's Restated Certificate of
Incorporation, dated June 23, 1993 (incorporated by reference to
the Company's Form 8-A, dated July 28, 1993, File No. 1-9874
("Form 8-A")).
3.3 Certificate of Amendment of the Company's Restated Certificate of
Incorporation dated, February 23, 1995 (incorporated by reference
to Exhibit 3.3 to the Company's Form 10-K/A Amendment (dated March
31, 1995) to the Company's Form 10-K for the year ended December
31, 1994, File No. 1-9874 (the "1994 Form 10-K")).
3.4 Certificate of Ownership and Merger, effective March 26, 1996.
(incorporated by reference to Exhibit 3.4 of the Company's Form 10-
K for the year ended December 31, 1995, File No. 1-9874 (the 1995
Form 10-K")).
3.5 Certificate of Amendment to the Company's Restated Certificate of
Incorporation dated May 19, 1997.
3.6 The Company's By-Laws as amended through February 21, 1997
(incorporated by reference to Exhibit 3.6 of the Company's Form 10-
K for the year ended December 31, 1996, File No. 1-9874 (the "1996
Form 10-K")).
4.1 Specimen copy of form of Common Stock Certificate (incorporated by
reference to Exhibit 4.1 to the Company's Form 10-K for the year
ended December 31, 1993, File No. 1-9874 (the "1993 Form 10-K")).
4.2 Shareholders Rights Agreement between the Company and
Manufacturers Hanover Trust Company of California dated December
1, 1988 (incorporated by reference to Exhibit 1 to Company's Form
8-K dated December 5, 1988, File No. 1-9874).
4.3 Amendment Number 1 to Shareholder Rights Agreement, dated February
15, 1991 (incorporated by reference to Exhibit 4.2 to the
Company's 1992 Form 10-K).
4.4 Escrow Deposit Agreement between Bank of American National Trust
and Savings Association and the Company dated March 3, 1994
(incorporated by reference to Exhibit 4.7 to the Company's 1993
Form 10-K).
10.1 Joint Venture Agreement for China Lake Joint Venture between the
Company and Caithness Geothermal 1980 Ltd., restated as of January
1, 1984 (incorporated by reference to Exhibit 10.1 to the
Company's Registration Statement on Form S-1, 33-7770).
10.2 Amended Joint Venture Agreement for Coso Land Company between the
Company and Caithness Geothermal 1980 Ltd., dated as of June 1,
1983 (incorporated by reference to Exhibit 10.3 to the Company's
Registration Statement on Form S-1, 33-7770).
10.3 Amended General Partnership Agreement for Coso Finance Partners
between China Lake Operating Company and ESCA I L.P. dated July
13, 1988 (incorporated by reference to Exhibit 10.3 to the
Company's 1992 Form 10-K).
10.4 First Supplemental Amendment to the Amended and Restated General
Partnership Agreement for Coso Finance Partners between China Lake
Operating Company and ESCA L.P. (Undated) (incorporated by
reference to Exhibit 10.4 to the Company's 1992 Form 10-K).
10.5 Second Supplemental Amendment to the Amended and Restated General
Partnership Agreement for Coso Finance Partners between China Lake
Operating Company and ESCA L.P. dated as of July 13, 1988
(incorporated by reference to Exhibit 10.5 to the Company's 1992
Form 10-K).
10.6 Third Supplemental Amendment to the Amended and Restated General
Partnership Agreement for Coso Finance Partners between China Lake
Operating Company and ESCA L.P. dated as of December 16, 1992
(incorporated by reference to Exhibit 10.6 to the Company's 1992
Form 10-K).
10.7 General Partnership Agreement for Coso Finance Partners II between
China Lake Geothermal Management Company and ESCA II L.P. dated
July 7, 1987 (incorporated by reference to Exhibit 10.7 to the
Company's 1992 Form 10-K).
10.8 Restated General Partnership Agreement for Coso Energy Developers
between Coso Hotsprings Intermountain Power Inc. and Caithness
Coso Holdings L.P. dated as of March 31, 1988 (incorporated by
reference to Exhibit 10.8 to the Company's 1992 Form 10-K).
10.9 First Amendment to the Restated General Partnership Agreement for
Coso Energy Developers between Coso Hotsprings Intermountain
Power, Inc. and Caithness Coso Holdings, L.P. dated as of March
31, 1988 (incorporated by reference to Exhibit 10.9 to the
Company's 1992 Form 10-K).
10.10 Second Amendment to the Restated General Partnership
Agreement for Coso Energy Developers between Coso Hotsprings
Intermountain Power, Inc. and Caithness Coso Holdings L.P. dated
as of December 16, 1992 (incorporated by reference to Exhibit
10.10 to the Company's 1992 Form 10-K).
10.11 Amended and Restated General Partnership Agreement for Coso
Power Developers between Coso Technology Corporation and Caithness
Navy II Group L.P. dated July 31, 1989 (incorporated by reference
to Exhibit 10.11 to the Company's 1992 Form 10-K).
10.12 First Amendment to the Amended and Restated General
Partnership for Coso Power Developers between Coso Technology
Corporation and Caithness Navy II Group L.P. dated as of March 19,
1991 (incorporated by reference to Exhibit 10.12 to the Company's
1992 Form 10-K).
10.13 Second Amendment to the Amended and Restated General
Partnership Agreement for Coso Power Developers between Coso
Technology Corporation and Caithness Navy II Group L.P. dated as
of December 16, 1992 (incorporated by reference to Exhibit 10.13
to the Company's 1992 Form 10-K).
10.14 Form of Amended and Restated Field Operation and Maintenance
Agreement between Coso Joint Ventures and the Company dated as of
December 16, 1992 (incorporated by reference to Exhibit 10.14 of
the Company's 1992 Form 10-K).
10.15 Form of Amended and Restated Project Operation and
Maintenance Agreement between Coso Joint Venture and the Company
dated as of December 16, 1992 (incorporated by reference to
Exhibit 10.15 to the Company's 1992 Form 10-K).
10.16 Trust Indenture between Coso Funding Corp. and Bank of
America National Trust and Savings Association dated as of
December 16 1992 (incorporated by reference to Exhibit 10.16 to
the Company's 1992 Form 10-K).
10.17 Form of Amended and Restated Credit Agreement between Coso
Funding Corp. and Coso Joint Ventures dated as of December 16,
1992 (incorporated by reference to Exhibit 10.17 to the Company's
1992 Form 10-K).
10.18 Form of Support Loan Agreement among Coso Joint Ventures
dated December 16, 1992 (incorporated by reference to Exhibit
10.18 to the Company's 1992 Form 10-K).
10.19 Form of Project Loan Pledge Agreement between Coso Joint
Ventures and Bank of America National Trust and Savings dated as
of December 16, 1992 (incorporated by reference to Exhibit 10.19
to the Company's 1992 Form 10-K).
10.20 Power Purchase Contracts between Southern California Edison
Company and:
(a) China Lake Joint Venture, executed June 4, 1984 with a
term of 24 years;
(b) China Lake Joint Venture, executed February 1, 1985 with
a term of 23 years; and
(c) Coso Geothermal Company, executed February 1, 1985 with
a term of 30 years (incorporated by reference to Exhibit 10.7
to the Company's Registration Statement on Form S-1, 33-
7770).
10.21 Contract No. N62474-79-C-5382 between the United States of
America and China Lake Joint Venture, restated October 19, 1983 as
"Modification P00004," including modifications through
"Modification P00026", dated December 16, 1992 (the "Navy
Contract")(incorporated by reference to Exhibit 10.21 to the
Company's 1992 Form 10-K).
10.22 Modification to Contract No. P00028, dated June 28, 1993,
Modification to Contract No. P00029, dated October 4, 1994 and
Modification to Contract No. P00031, dated December 19, 1994 all
amending the Navy Contract "(incorporated by reference to Exhibit
10.22 to the Company's 1994 Form 10-K)."
10.23 Lease between the BLM and Coso Land Company, effective
November 1, 1985 (with Designation of Geothermal Operator)
(incorporated by reference to Exhibit 10.8 to the Company's
Registration Statement on Form S-1, 33-7770).
10.24 1996 Employee Stock Option Plan, as amended (incorporated by
reference to Exhibit A to the Company's 1996 Proxy Statement).
10.25 1994 Employee Stock Purchase Plan (incorporated by reference
to Exhibit A to the Company's 1994 Proxy Statement).
10.26 Indenture between the Company and The Chemical Trust Company
of California dated as of June 24, 1993 (incorporated by reference
to the Company's Form 8-K dated June 24, 1993, File No. 1-9874).
10.27 Registration Rights Agreement among the Company, Lehman
Brothers, Inc. and Alex Brown & Sons Incorporated dated June 24,
1993 (incorporated by reference to the Company's Form 8-K dated
June 24, 1993, File No. 1-9874).
10.28 Indenture dated March 24, 1994 between the Company and IBJ
Schroder Bank and Trust Company (incorporated by reference to
Exhibit 3 to the Company's Form 8-K dated March 28, 1994).
10.29 Amended and Restated Employment Agreement between the Company
and David L. Sokol dated as of August 21, 1995 (incorporated by
reference to Exhibit 10.82 to the Company's 1995 Form 10-K).
10.30 Restricted Stock Exchange Agreement between the Company and
David L. Sokol dated as of November 29, 1995 (incorporated by
reference to Exhibit 10.43 to the Company's 1995 Form 10-K).
10.31 Amendment No. 1 to the Amended and Restated Employment
Agreement between the Company and David L. Sokol, dated August 28,
1996 (incorporated by reference to Exhibit 10.43 to the Company's
1996 Form 10-K).
10.32 Amendment No. 2 to the Amended and Restated Employment
Agreement between the Company and David L. Sokol dated April 16,
1997.
10.33 Employment Agreement between the Company and Gregory E. Abel,
dated August 6, 1996 (incorporated by reference to Exhibit 10.44
to the Company's 1996 Form 10-K).
10.34 Amendment No. 1 to the Employment Agreement between the
Company and Gregory E. Abel dated April 16,
1997.
10.35 Employment Agreement between the Company and Craig M.
Hammett, dated January 11, 1998.
10.36 Amendment No. 1 to the Employment Agreement between the
Company and Craig M. Hammett dated January 12, 1998.
10.37 Employment Agreement between the Company and Steven A.
McArthur, dated August 6, 1996 (incorporated by reference to
Exhibit 10.46 to the Company's 1996 Form 10-K).
10.38 Amendment No. 1 to the Employment Agreement between the
Company and Steven A. McArthur dated April 16, 1997.
10.39 Standard Offer Number 2, Standard Offer for Power Purchase
with a Firm Capacity Qualifying Facility effective June 15, 1990
("SO2") between San Diego Gas & Electric Company and Bonneville
Pacific Corporation (incorporated by reference to Exhibit 10.42 to
the Company's 1993 Form 10-K).
10.40 Amendment Number One to the SO2 dated September 25, 1990
(incorporated by reference to Exhibit 10.43 to the Company's 1993
Form 10-K).
10.41 Reserved
10.42 Reserved
10.43 Reserved
10.44 Stock Purchase Agreement between CalEnergy Imperial Valley
Company, Inc. and Edison Mission Energy, dated as of March 27,
1996 (incorporated by reference to Exhibit 10.50 to the Company's
1995 Form 10-K).
10.45 Standard Offer No. 4 Power Purchase Agreement (Elmore), dated
June 15, 1984, between Southern California Edison Company and
Magma Electric Company including Amendments No. 1 and No. 2
(incorporated by reference to Exhibit 10.14 to Magma Power
Company's Amendment No. 1 to Registration Statement Form S-4 dated
February 2, 1988, ("Magma 1988 Form S-4")).
10.46 Standard Offer No. 4 Power Purchase Agreement (Del Ranch)
dated February 22, 1984, between Southern California Edison
Company and Imperial Energy Corporation, including Amendments No.
1 and No. 2 (incorporated by reference to Exhibit 10.15 to the
Magma 1988 Form S-4).
10.47 Standard Offer No. 4 Power Purchase Agreement (Vulcan), dated
June 15, 1984, between Southern California Edison Company and
Magma Electric Company including Amendment No. 1 (incorporated by
reference to Exhibit 10.16 to the Magma 1988 Form S-4).
10.48 Standard Offer No. 4 Power Purchase Agreement (River Ranch),
dated April 16, 1985, between Southern California Edison Company
and Imperial Energy Corporation, including Amendment No. 1
(incorporated by reference to Exhibit 10.20 to the Magma 1988 Form
S-4).
10.49 Partnership Agreement dated August 30, 1985 between Vulcan
Power Company and BN Geothermal, Inc. (incorporated by reference
to Exhibit 10.88 to the Magma Power Company's Form 8 Amendment
(dated December 18, 1990) to Magma Power Company's Form 10-K for
the year ended December 31, 1989 ("Magma Form 8")).
10.50 Amended and Restated Limited Partnership Agreement of Del
Ranch, Ltd., a California Limited Partnership, dated March 14,
1988 by and among Red Hill Geothermal, Inc. and Conejo Energy
Company, as General Partners, and Magma Power Company and Conejo
Energy Company, as Original Limited Partners (incorporated by
reference to Exhibit 10.53 to the Magma Power Company Annual
Report on Form 10-K for the year ended December 31, 1987, File No.
0-10533 ("1987 Magma Form 10-K")).
10.51 Limited Partnership Agreement of Leathers, L.P., dated August
15, 1988 by and among Red Hill Geothermal, Inc. and San Felipe
Energy Company, as General Partners, and Magma Power Company and
San Felipe Energy Company, as Limited Partners (incorporated by
reference to Exhibit 10.79 to the Magma Power Company Annual
Report on Form 10-K for the year ended December 31, 1988, File No.
0-10533 ("1988 Magma Form 10-K")).
10.52 Amended and Restated Limited Partnership Agreement of Elmore,
Ltd., a California Limited Partnership, dated March 14, 1988 by
and among Red Hill Geothermal, Inc. and Niguel Energy Company, as
General Partners, and Magma Power Company and Niguel Energy
Company, as Original Limited Partners (incorporated by reference
to Exhibit 10.55 to the 1987 Magma Form 10-K).
10.53 Operating and Maintenance Agreement dated March 14, 1988 by
and between Red Hill Geothermal, Inc. and Del Ranch, Ltd., a
California Limited Partnership (incorporated by reference to
Exhibit 10.56 to the 1987 Magma Form 10-K).
10.54 First Amendment to Operating and Maintenance Agreement dated
as of April 14, 1989 between Red Hill Geothermal, Inc. and Del
Ranch L.P. and the Second Amendment to the Operating and
Maintenance Agreement dated April 18, 1990 "(incorporated by
reference to Exhibit 10.60 to the Company's Form 10-K/A Amendment
(dated March 31, 1995) to the Company's 1994 Form 10-K)."
10.55 Operating and Maintenance Agreement dated August 15, 1988 by
and between Red Hill Geothermal, Inc. and Leathers, L.P.
(incorporated by reference to Exhibit 10.84 to the 1988 Magma Form
10-K).
10.56 First Amendment to Operating and Maintenance Agreement dated
as of April 14, 1989 between Red Hill Geothermal, Inc. and
Leathers, L.P. and the Second Amendment to the Operating and
Maintenance Agreement dated April 18, 1990 "(incorporated by
reference to Exhibit 10.62 to the Company's 1994 Form 10-K)."
10.57 Operating and Maintenance Agreement dated March 14, 1988 by
and between Red Hill Geothermal, Inc. and Elmore, Ltd., a
California Limited Partnership (incorporated by reference to
Exhibit 10.57 to the 1987 Magma Form 10-K).
10.58 First Amendment to the Operating and Maintenance Agreement
dated as of April 14, 1988 between Red Hill Geothermal, Inc. and
Elmore, Ltd., a California Limited Partnership and the Second
Amendment to the Operating and Maintenance Agreement dated April
18, 1990 "(incorporated by reference to Exhibit 10.64 to the
Company's 1994 Form 10-K)."
10.59 Brine Sales Agreement dated August 30, 1985 between Vulcan
Power Company and Vulcan/BN Geothermal Power Company (incorporated
by reference to Exhibit 10.90 to the Magma Power Company Form 8
Amendment (dated December 18, 1990) to the Magma Power Company
Form 10-K for the year ended December 31, 1989).
10.60 Easement Grant Deed and Agreement Regarding Rights for
Geothermal Development dated March 14, 1988 by and between Magma
Power Company and Del Ranch, Ltd., a California Limited
Partnership (incorporated by reference to Exhibit 10.58 to the
1987 Magma Form 10-K).
10.61 Easement Grant Deed and Agreement Regarding Rights for
Geothermal Development dated August 15, 1988 by and between Magma
Power Company and Leathers, L.P. (incorporated by reference to the
1988 Magma Form 10-K).
10.62 Easement Grant Deed and Agreement Regarding Rights for
Geothermal Development dated March 14, 1988 by and between Magma
Power Company and Elmore, Ltd., a California Limited Partnership
(incorporated by reference to Exhibit 10.59 to the 1987 Magma Form
10-K).
10.63 Administrative Services Agreement dated March 14, 1988 by and
between Red Hill Geothermal, Inc. and Del Ranch, Ltd., a
California Limited Partnership (incorporated by reference to the
1987 Magma Form 10-K).
10.64 Administrative Services Agreement dated August 15, 1988 by
and between Red Hill Geothermal, Inc. and Leathers, L.P.
(incorporated by reference to Exhibit 10.82 to the 1988 Magma Form
10-K).
10.65 Administrative Services Agreement dated March 14, 1988 by and
between Red Hill Geothermal Inc. and Elmore, Ltd., a California
Limited Partnership (incorporated by reference to Exhibit 10.63 to
the 1987 Magma Form 10-K).
10.66 Amended and Restated Credit Agreement dated as of April 18,
1990 among Del Ranch, Ltd. a California Limited Partnership, the
Banks Listed therein, and Morgan Guaranty Trust Company of New
York, as Agent (incorporated by reference to Exhibit 10.72 to the
Company's 1994 Form 10-K).
10.67 LOC Debt Facility Agreement dated as of April 18, 1990 among
Del Ranch, Ltd., a California Limited Partnership, the Banks
listed therein, Morgan Guaranty Trust Company of New York as the
Agent and Fuji Bank, Limited, Los Angeles Agency, as Fronting Bank
(incorporated by reference to Exhibit 10.73 to the Company's 1994
Form 10-K).
10.68 Security Agreement dated March 14, 1988 among Del Ranch,
Ltd., a California Limited Partnership, Morgan Guaranty Trust
Company of New York, as Agent for and on behalf of the Banks,
Morgan Guaranty Trust Company of New York, and Morgan Guaranty
Trust Company of New York, as Security Agent (incorporated by
reference to the 1987 Magma Form 10-K).
10.69 Amendment Number One to Security Agreement dated as of April
14, 1989, and Amendment Number Two to the Security Agreement dated
April 18, 1990 among Del Ranch, Ltd., a California Limited
Partnership, Morgan Guaranty Trust Company of New York, as Agent
for and on behalf of the Banks, Morgan Guaranty Trust Company of
New York and Morgan Guaranty Trust Company of New York as Security
Agent (incorporated by reference to Exhibit 10.75 to the Company's
1994 Form 10-K).
10.70 Deed of Trust, Assignment of Rents, Security Agreement and
Fixture Filing Construction Deed of Trust dated as of March 14,
1988 among Del Ranch, Ltd., a California Limited Partnership,
Ticor Title Insurance Company of California, and Morgan Guaranty
Trust Company of New York as Security Agent (incorporated by
reference to the 1987 Magma Form 10-K).
10.71 First Amendment to the Deed of Trust, dated April 18, 1990
between Del Ranch, Ltd. and Morgan Guaranty Trust Company of New
York (incorporated by reference to Exhibit 10.77 to the Company's
1994 Form 10-K).
10.72 Amended and Restated Credit Agreement dated as of April 18,
1990 among Elmore, Ltd., a California Limited Partnership, the
Banks Listed therein, and Morgan Guaranty Trust Company of New
York, as Agent (incorporated by reference to Exhibit 10.78 to the
Company's 1994 Form 10-K).
10.73 LOC Debt Facility Agreement dated as of April 18, 1990 among
Elmore, Ltd., a California Limited Partnership, the Banks listed
therein, Morgan Guaranty Trust Company of New York as Agent and
Fuji Bank, Limited, Los Angeles Agency, as Fronting Bank
(incorporated by reference to Exhibit 10.79 to the Company's 1994
Form 10-K).
10.74 Security Agreement dated March 14, 1988 among Elmore, Ltd., a
California Limited Partnership, Morgan Guaranty Trust Company of
New York, as Agent for and on behalf of the Banks, Morgan Guaranty
Trust Company of New York, and Morgan Guaranty Trust Company of
New York, as Security Agent (incorporated by reference to Exhibit
10.71 to the 1987 Magma Form 10-K).
10.75 Amendment Number One to Security Agreement dated as of April
14, 1989 among Elmore Ltd and Morgan Guaranty Trust Company of New
York and Amendment Number Two to Security Agreement dated April
18, 1990 among Elmore, L.P., Morgan Guaranty Trust Company of New
York, as Agent, on behalf of the Banks (incorporated by reference
to Exhibit 10.81 to the Company's 1994 Form 10-K).
10.76 Deed of Trust, Assignment of Rents, Security Agreement and
Fixture Filing Construction Deed of Trust dated as of March 14,
1988 among Elmore, Ltd., a California Limited Partnership, Ticor
Title
Insurance Company of California, and Morgan Guaranty Trust Company
of New York as Security Agent (incorporated by reference to
Exhibit 10.73 to the 1987 Magma Form 10-K).
10.77 First Amendment to Deed of Trust dated April 18, 1990 between
Elmore, Ltd. and Morgan Guaranty Trust Company of New York, as
Security Agent (incorporated by reference to Exhibit 10.83 to the
Company's 1994 Form 10-K).
10.78 Amended and Restated Credit Agreement dated April 18, 1990
among Leathers L.P. and the Banks listed therein and Morgan
Guaranty Trust Company of New York as Agent (incorporated by
reference to Exhibit 10.84 to the Company's 1994 Form 10-K).
10.79 Security Agreement dated March 14, 1988 among Leathers L.P.,
a California Limited Partnership, Morgan Guaranty Trust Company of
New York, as Agent for and on behalf of the Banks, Morgan Guaranty
Trust Company of New York, and Morgan Guaranty Trust Company of
New York, as Security Agent, Amendment Number One to Security
Agreement dated as of April 14, 1989 and Amendment Number Two to
Security Agreement dated as of April 18, 1990 (incorporated by
reference to Exhibit 10.85 to the Company's 1994 Form 10-K).
10.80 Deed of Trust, Assignment of Rents, Security Agreement and
Fixture Filing Construction Deed of Trust dated as of March 14,
1988 among Leathers, L.P., a California Limited Partnership, Ticor
Title Insurance Company of California, and Morgan Guaranty Trust
Company of New York as Security Agent and First Amendment to Deed
of Trust dated April 18, 1990 (incorporated by reference to
Exhibit 10.85 to the Company's 1994 Form 10-K).
10.81 LOC Debt Facility Agreement dated as of April 18, 1990 among
Leathers, L.P., a California Limited Partnership, the Banks listed
therein, Morgan Guaranty Trust Company of New York as Agent and
Fuji Bank, Limited, Los Angeles Agency, as Fronting Bank
(incorporated by reference to Exhibit 10.87 to the Company's 1994
Form 10-K).
10.82 Loan Agreement dated as of October 1, 1990 between California
Pollution Control Financing Authority and Desert Valley Company,
relating to the California Pollution Control Financing Authority
Pollution Control Revenue Bonds Small Business Series 1990-A (the
"$4,000,000 Monofill Bond Financing") (incorporated by reference
to Exhibit 10.92 to the Magma Power Company Form 10-K for the year
ended December 31, 1990, File No. 0-10533 (the "1990 Magma Form 10-
K")).
10.83 Master Reimbursement Agreement dated as of October 1, 1990,
by and among the California Pollution Control Financing Authority,
Desert Valley Company and the Sanwa Bank, Limited, Los Angeles
Branch, relating to the $4,000,000 Monofill Bond Financing
(incorporated by reference to Exhibit 10.93 to the 1990 Magma Form
10-K).
10.84 Sale and Purchase Agreement between Union Oil Company of
California and Magma Power Company effective as of December 31,
1992 (incorporated by reference to Exhibit 10.97 to the Magma
Power Company Form 8 dated June 2, 1993).
10.85 Contract for the Purchase and Sale of Electric Power (Unit I)
from the Salton Sea Geothermal Generating Facility between
Southern California Edison Company and Earth Energy, Inc., dated
May 8, 1987, including Amendment No. 1 to such contract, dated
March 30, 1993 (incorporated by reference to Exhibit 10.101 to the
Magma Power Company Form 10-K for the year ended December 31,
1993, File No. 0-10533, (the "1993 Magma Form 10-K")).
10.86 Power Purchase Contract (Unit II) by and between Southern
California Edison Company and Westmoreland Geothermal Associates,
dated April 16, 1985, including Amendment No. 1 to such contract,
dated December 18, 1987 (incorporated by reference to Exhibit
10.102 to the 1993 Magma Form 10-K).
10.87 Power Purchase Contract (Unit III) between Southern
California Edison Company and Union Oil Company Salton Sea III,
dated April 16, 1985 (incorporated by reference to the 1993 Magma
Form 10-K).
10.88 Consolidated, Amended and Restated Power Purchase Agreement
(Unit IV) between Southern California Edison Company and Fish Lake
Power Company and Salton Sea Power Generation, L.P. (incorporated
by reference to Exhibit 10.9 to the Registration Statement on Form
S-4 dated August 9, 1995 of Salton Sea Funding Corporation 33-
95538 (the "Funding Corporation S-4").
10.89 125 MW Power Plant - Upper Mahiao Agreement (the "Upper
Mahiao ECA") dated September 6, 1993 between PNOC-Energy
Development Corporation ("PNOC-EDC") and Ormat, Inc. as amended by
the First Amendment to 125 MW Power Plant Upper Mahiao Agreement
dated as of January 28, 1994, the Letter Agreement dated February
10, 1994, the Letter Agreement dated February 18, 1994 and the
Fourth Amendment to 125 MW Power Plant - Upper Mahiao Agreement
dated as of March 7, 1994 (incorporated by reference to Exhibit
10.95 to the Company's 1994 Form 10-K).
10.90 Credit Agreement dated April 8, 1994 among CE Cebu Geothermal
Power Company, Inc., the Banks thereto, Credit Size as Agent
(incorporated by reference to Exhibit 10.96 to the Company's 1994
Form 10-K).
10.91 Credit Agreement dated as of April 8, 1994 between CE Cebu
Geothermal Power Company, Inc., Export-Import Bank of the United
States (incorporated by reference to Exhibit 10.97 to the
Company's 1994 Form 10-K).
10.92 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).
10.93 Overseas Private Investment Corporation Contract of Insurance
dated April 8, 1994 between the Overseas Private Investment
Corporation ("OPIC") and the Company through its subsidiaries CE
International Ltd., CE Philippines Ltd., and Ormat-Cebu Ltd.
(incorporated by reference to Exhibit 10.99 to the Company's 1994
Form 10-K).
10.94 180 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).
10.95 Credit Agreement dated as of June 30, 1994 among CE Luzon
Geothermal Power Company, Inc., American Pacific Finance Company,
the Lenders party thereto, and Bank of America National Trust and
Savings Association as Administrative Agent (incorporated by
reference to Exhibit 10.101 to the Company's 1994 Form 10-K).
10.96 Credit Agreement dated as of June 30, 1994 between CE Luzon
Geothermal Power Company, Inc. and Export-Import Bank of the
United States (incorporated by reference to Exhibit 10.102 to the
Company's 1994 Form 10-K).
10.97 Finance Agreement dated as of June 30, 1994 between CE Luzon
Geothermal Power Company, Inc. and Overseas Private Investment
Corporation (incorporated by reference to Exhibit 10.103 to the
Company's 1994 Form 10-K).
10.98 Pledge Agreement dated as of June 30, 1994 among CE
Mahanagdong Ltd., Kiewit Energy International (Bermuda) Ltd., Bank
of America National Trust and Savings Association as Collateral
Agent and CE Luzon Geothermal Power Company, Inc. (incorporated by
reference to Exhibit 10.104 to the Company's 1994 Form 10-K).
10.99 Overseas Private Investment Corporation Contract of Insurance
dated July 29, 1994 between OPIC and the Company, CE International
Ltd., CE Mahanagdong Ltd. and American Pacific Finance Company and
Amendment No. 1 dated August 3, 1994 (incorporated by reference to
Exhibit 10.105 to the Company's 1994 Form 10-K).
10.100 231 MW Power Plant - Malitbog Agreement ("Malitbog ECA")
dated September 10, 1993 between PNOC-EDC and Magma Power Company
and the First and Second Amendments thereto dated December 8, 1993
and March 10, 1994, respectively (incorporated by reference to
Exhibit 10.106 to the Company's 1994 Form 10-K).
10.101 Credit Agreement dated as of November 10, 1994 among Visayas
Power Capital Corporation, the Banks parties thereto and Credit
Suisse Bank Agent (incorporated by reference to Exhibit 10.107 to
the Company's 1994 Form 10-K).
10.102 Finance Agreement dated as of November 10, 1994 between
Visayas Geothermal Power Company and Overseas Private Investment
Corporation (incorporated by reference to Exhibit 10.108 to the
Company's 1994 Form 10-K).
10.103 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).
10.104 Overseas Private Investment Corporation Contract of Insurance
dated December 21, 1994 between OPIC and Magma Netherlands, B.V.
(incorporated by reference to Exhibit 10.110 to the Company's 1994
Form 10-K).
10.105 Agreement as to Certain Common Representations, Warranties,
Covenants and Other Terms, dated November 10, 1994 between Visayas
Geothermal Power Company, Visayas Power Capital Corporation,
Credit Suisse, as Bank Agent, OPIC and the Banks named therein
(incorporated by reference to Exhibit 10.111 to the Company's 1994
Form 10-K).
10.106 Indenture dated as of July 21, 1995 between Salton Sea
Funding Corporation ("Funding Corporation") and Chemical Trust
Company of California (incorporated by reference to Exhibit 4.1(a)
to the Funding Corporation Form S-4).
10.107 First Supplemental Indenture dated as of October 18, 1995
between Funding Corporation and Chemical Trust Company of
California (incorporated by reference to Exhibit 4.1(b) to the
Funding Corporation Form S-4).
10.108 Indenture dated July 1995 between the Company and The Bank of
New York (incorporated by reference to the Company's Amendment No.
1 to Registration Statement on Form S-3 dated May 17, 1995).
10.109 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")).
10.110 Modification to Contract No. P00019 dated August 1, 1995,
Modification to Contract No. P00020 dated August 1, 1995,
Modification to Contract No. P00034 dated February 8, 1995 and
Modification to Contract No. P00035 dated February 8, 1995,
amending the Navy Contract (incorporated by reference to Exhibit
10.110 to the Company's 1996 Form 10-K).
10.111 Plant Connection Agreement between Imperial Irrigation
District and Salton Sea Power Generation L.P. and Fish Lake Power
Company dated July 14, 1995 (incorporated by reference to Exhibit
10.15 to the Funding Corporation S-4).
10.112 Transmission Services Agreement between Imperial Irrigation
District and Salton Sea Power Generation L.P. and Fish Lake Power
Company dated July 14, 1995 (incorporated by reference to Exhibit
10.17 to the Funding Corporation S-4).
10.113 Second Amended and Restated Administrative Services Agreement
among CalEnergy Operation Company, Salton Sea Brine Processing
L.P., Salton Sea Power Generation L.P. and Fish Lake Power Company
dated July 15, 1995 (incorporated by reference to Exhibit 10.20 to
the Funding Corporation S-4).
10.114 Second Amended and Restated Operating and Maintenance
Agreement among Magma Power Company, Salton Sea Brine Processing
L.P., Salton Sea Power Generation L.P., and Fish Lake Power
Company dated July 15, 1995 (incorporated by reference to Exhibit
10.21 to the Funding Corporation S-4).
10.115 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).
10.116 Stock Purchase Agreement, dated as of July 3, 1996, by and
among CE/FS Holding Company, Inc., David H. Dewhurst and all
remaining owners of capital stock of Falcon Seaboard Resources,
Inc. (incorporated by reference to Exhibit 99.1 to the Company's
Form 8-K, dated July 8, 1996, File No. 1-9874).
10.117 Indenture for the 6 1/4% Convertible Junior Subordinated
Debentures, dated as of April 1, 1996, among CalEnergy Company,
Inc., as Issuer, and the Bank of New York, as Trustee
(incorporated by reference to Exhibit 4.3 to Amendment 1 to the
Company's Registration Statement on Form S-3, Registration No. 333-
08315).
10.118 Indenture, dated as of September 20, 1996, between the
Company and IBJ Schroder Bank & Trust Company, as trustee,
relating to $225,000,000 principal amount of 9 1/4% Senior Notes
due 2006 (incorporated by reference to Exhibit 4.1 to the
Company's Registration Statement on Form S-3, Registration No. 333-
15591).
10.119 Second Supplemental Indenture, dated as of June 20, 1996,
between Chemical Trust Company of California and Funding
Corporation (incorporated by reference to Exhibit 4.1(c) to
Amendment No. 1 to the Funding Corporation's Registration
Statement on Form S-4, Registration No. 333-07527 ("Funding Corp.
II S-4").
10.120 Third Supplemental Indenture, between Chemical Trust Company
of California and the Funding Corporation (incorporated by
reference to Exhibit 4.1(d) to the Funding Corp. II S-4).
10.121 Indenture for the 6 1/4% Convertible Junior Subordinated
Debentures due 2012, dated as of February 26, 1997, between the
Company, as issuer, and the Bank of New York, as Trustee
(incorporated by reference to Exhibit 10.129 to the Company's 1996
Form 10-K).
10.122 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).
10.123 Public Electricity Supply License (incorporated by reference
to Exhibit 10.131 to the Company's 1996 Form 10-K)
10.124 Second Tier Supply Licenses to Supply Electricity for England
& Wales and Scotland (incorporated by reference to Exhibit 10.132
to the Company's 1996 Form 10-K).
10.125 Pooling and Settlement Agreement for the Electricity Industry
in England and Wales dated 30th March, 1990 (as amended at 17th
October, 1996), among The Generators (named therein), the
Suppliers (named therein), Energy Settlements and Information
Services Limited (as Settlement System Administrator), Energy Pool
Funds Administration Limited (as Pool Funds Administrator),
Scottish Power plc, Electricite deFrance, Service National and
Others (incorporated by reference to Exhibit 10.133 to the
Company's 1996 Form 10-K).
10.126 Master Connection and User System Agreement with The National
Grid Company plc (incorporated by reference to Exhibit 10.134 to
the Company's 1996 Form 10-K).
10.127 Gas Suppliers License dated February 21, 1996 (incorporated
by reference to Exhibit 10.135 to the Company's 1996 Form 10-K).
10.128 First Supplemental Trust Indenture dates as of February 18,
1997 between Coso Funding Corp. and First Bank, National
Association (successor to Bank of America Nation Trust and Savings
Association) (incorporated by reference to Exhibit 10.136 to the
Company's 1996 Form 10-K).
10.129 Form First Amendment to Amended and Restated Credit
Agreement, dated February 18, 1997, between First Bank, National
Association (as successor to Coso Funding Corp.) and the Coso
Joint Ventures (incorporated by reference to Exhibit 10.137 to the
Company's 1996 Form 10-K).
10.130 Omnibus Acknowledgment and Agreement dated February 18, 1997
between Coso Funding Corp., the Coso Joint Ventures, First Bank,
National Association and others (incorporated by reference to
Exhibit 10.138 to the Company's 1996 Form 10-K).
10.131 Registration Rights Agreement, dated August 12, 1997, by and
among CalEnergy Capital Trust III, CalEnergy Company, Inc., Credit
Suisse First Boston Corporation and Lehman Brothers, Inc.
(incorporated by reference Exhibit 10.1 to the Company's
Registration Statement and on Form S-3, No. 333-45615).
10.132 Acquisition Agreement by and between CalEnergy Company, Inc.
and Kiewit Diversified Group Inc. dated as of September 10, 1997
(incorporated by reference to Exhibit 2 to the Company's Current
Report on Form 8-K dated September 11, 1997).
10.133 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).
10.134 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).
13.0 The Company's 1997 Annual Report (only the portions thereof
specifically incorporated herein by reference are deemed filed
herewith).
21.0 Subsidiaries of Registrant.
23.0 Consent of Independent Auditors.
24.0 Power of Attorney.
27.1 Financial Data Schedule.
27.2 Restated Financial Data Schedule - fiscal year ended December 31,
1995 and 1996 and the three, six, and nine months ended March 31,
1996, June 30, 1996 and September 30, 1996, respectively.
27.3 Restated Financial Data Schedule - three, six and nine months
ended March 31, 1997, June 30, 1997 and September 30, 1997,
respectively.
Exhibit 3.5
CERTIFICATE OF AMENDMENT
TO THE
CERTIFICATE OF INCORPORATION
OF
CALENERGY COMPANY, INC.
CALENERGY COMPANY, INC., a Delaware corporation (the
"Company"), HEREBY CERTIFIES AS FOLLOWS:
FIRST: The name of the Company is CalEnergy Company,
Inc. The date of the filing of the Company's most recent
Certificate of Amendment to the Restated Certificate of
Incorporation with the Secretary of State of the State of
Delaware was February 23, 1995; provided, however, that such
Restated Certificate of Incorporation was further amended by
a Certificate of Ownership and Merger dated March 22, 1996,
which amended the Company's name.
SECOND: That the following resolution was approved and
adopted by the Board of Directors of the Company.
THIRD: That the following resolution was approved and
adopted pursuant to authorization by the stockholders of the
Company at the annual meeting of the Company's stockholders
duly called and held on May 15, 1997:
RESOLVED: That paragraph A of Article Fourth of the
Company's Restated Certificate of Incorporation be
deleted in its entirety and the following be and hereby
is inserted in lieu thereof:
FOURTH: A. The Corporation is authorized to
issue two classes of shares of stock, to be designated
respectively as Preferred Stock shares and as Common
Stock shares. The total number of shares of all
classes of stock which the Corporation shall have
authority to issue is One Hundred Eighty Two Million
(182,000,000) shares, and the aggregate par value of
all shares that are to have a par value is Twelve
Million One Hundred Fifty Thousand Dollars
($12,150,000). The number of Preferred Stock shares is
Two Million (2,000,000) shares, each without par value.
The number of Common Stock shares that are to have a
par value is One Hundred Eighty Million (180,000,000),
and each such Common Stock share is to have a par value
of Six and Seventy-Five One Hundredths Cents ($0.0675)
per share.
FOURTH: That said amendment herein certified was duly
adopted in accordance with Section 242 of the General
Corporation Law of the State of Delaware.
The effective time of the amendment herein certified
shall be immediately upon filing.
IN WITNESS WHEREOF, CALENERGY COMPANY, INC. has caused
this Certificate to be executed and attested by the
undersigned, this 19th day of May, 1997.
CALENERGY COMPANY, INC.
By: /s/ Steven A. McArthur
Name: Steven A. McArthur
Title: Secretary
ATTEST:
By: /s/ Douglas L. Anderson
Name: Douglas L. Anderson
Title: Assistant Secretary
Exhibit 10.32
AMENDMENT NO. 2
TO THE
AMENDED AND RESTATED EMPLOYMENT AGREEMENT
BETWEEN
CALENERGY COMPANY, INC.
AND DAVID SOKOL
This Amendment No. 2 (the "Amendment") to the Amended
and Restated Employment Agreement dated as of August 21, 1995, as
further amended by Amendment No. 1 thereto (the "Employment
Agreement") by and between CalEnergy Company, Inc., a Delaware
Corporation (the "Company"), and David L. Sokol (the
"Executive"), is entered into as of April 16, 1997.
WHEREAS, the Company and the Executive are presently
parties to the Employment Agreement; and
WHEREAS, the Company and the Executive desire to amend
the Employment Agreement as set forth herein;
NOW, THEREFORE, the Employment Agreement is hereby
amended as follows:
(1) By adding the following sentences at the end of
Section 4(c):
"The Executive shall also be eligible to
be paid other bonuses for each fiscal
year as determined by the Board. The
Executive's annual bonus, together with
all such other bonuses paid or payable
for the fiscal year (including any
amounts for which receipt is otherwise
deferred pursuant to a plan or
arrangement with the Company), is
referred to herein as `Annual Bonus
Compensation.'"
(2) By adding the following sentence after the last
sentence of Section 6(a):
"The preceding sentence notwithstanding,
if the Executive's resignation occurs
upon or after a Change in Control (as
defined in the Restricted Stock Exchange
Agreement between the Company and the
Executive dated as of November 29,
1995), he shall not be precluded from
accepting employment or providing
services to Peter Kiewit Sons', Inc. or
any affiliate thereof."
(3) By deleting the first sentence of Section 8(b) of
the Employment Agreement and replacing it with the following
sentence:
"If the employment of the Executive is
terminated pursuant to subsections (ii),
(iv), (v) or (vi) of Section 7(a), the
Company will pay the Executive, on or
before the related Termination Date, an
amount equal to three times the sum of
(1) the annual salary then in effect
pursuant to Section 4, and (2) the
greater of (x) the Minimum Bonus or (y)
an amount equal to the average Annual
Bonus Compensation payable to the
Executive in respect of the two fiscal
years immediately preceding the fiscal
year in which the Executive's employment
with the Company terminates."
(4) By inserting immediately following Section 8(b) a
new Section 8(c), to read as follows:
"(c) If the employment of the Executive
is terminated pursuant to subsections
(ii) or (iv) of Section 7(a), all
Performance Accelerated Stock Options
("PASOs") held by the Executive on the
Termination Date will become vested and
immediately exercisable on such
Termination Date, and shall otherwise
remain exercisable for their term in
accordance with the terms thereof."
(5) By inserting immediately following Section 8(c) a
new Section 8(d) to read as follows:
"(d) If the employment of the Executive
is terminated for any reason after a
Change in Control (as defined in the
Restricted Stock Exchange Agreement
between the Company and the Executive
dated as of November 29, 1995), then
without further action by the Company,
the Board or any committee thereof, the
Executive may exercise any vested stock
options (including vested PASOs) held by
the Executive pursuant to existing
procedures approved by the Stock Option
Committee for cashless exercise, by
surrendering previously owned shares,
electing to have the Company withhold
shares otherwise deliverable upon
exercise of such options, or by
providing an irrevocable direction to a
broker to sell shares and deliver all or
a portion of the proceeds to the
Company, in any case in an amount equal
to the aggregate exercise price and any
tax withholding obligation attendant to
the exercise."
Except as provided herein and to the extent necessary
to give full effect to the provisions of this Amendment, the
terms of the Employment Agreement shall remain in full force and
effect.
IN WITNESS WHEREOF, the parties hereto have entered
into this Amendment effective as of April 16, 1997.
CALENERGY COMPANY, INC.
By: /s/ Steven A. McArthur
Name: Steven A. McArthur
Title: Senior Vice President
EXECUTIVE
/s/ David L. Sokol
David L. Sokol
Exhibit 10.34
AMENDMENT NO. 1
TO THE
EMPLOYMENT AGREEMENT
BETWEEN
CALENERGY COMPANY, INC.
AND
GREGORY E. ABEL
This Amendment No. 1 (the "Amendment") to the
Employment Agreement dated August 6, 1996 (the "Employment
Agreement") by and between CalEnergy Company, Inc., a
Delaware corporation (the "Company"), and Gregory E. Abel
(the "Executive"), is entered into as of April 16, 1997.
WHEREAS, the Company and the Executive are
presently parties to the Employment Agreement; and
WHEREAS, the Company and the Executive desire to
amend the Employment Agreement as set forth herein;
NOW, THEREFORE, the Employment Agreement is hereby
amended as follows:
(1) By adding the following sentences at the end
of Section 4(c):
"The Executive shall also be eligible to be
paid other bonuses for each fiscal year as
determined by the Chairman of the Board. The
Executive's annual incentive merit bonus,
together with all such other bonuses paid or
payable for the fiscal year (including any
amounts for which receipt is otherwise
deferred pursuant to a plan or arrangement
with the Company), is referred to herein as
`Annual Bonus Compensation.'"
(2) By adding the following sentence after the
last sentence of Section 6 (a):
"The preceding sentence notwithstanding, if
the Executive's resignation occurs upon or
after a Change in Control, he shall not be
precluded from accepting employment or
providing services to Peter Kiewit Sons',
Inc. or any affiliate thereof."
(3) By deleting from the first sentence of
Section 8(b) the language following the parenthetical
"(iii)" and replacing it with the following:
"commencing one month after the month of his
Termination Date, 24 monthly payments each
equal to 1/24 of a sum equal to two times the
average Annual Bonus Compensation payable to
the Executive in respect of the two fiscal
years immediately preceding the year in which
the Executive's employment with the Company
terminates (with any such year for which no
bonus was payable included in such two year
average as a zero)."
(4) By deleting current Section 8(d) and
inserting new Section 8(d), to read as follows:
"(d) If the employment of the Executive is
terminated pursuant to subsections (ii) or
(vi) of Section 7(a), all Performance
Accelerated Stock Options ("PASOs") held by
the Executive on the Termination Date will
become vested and immediately exercisable on
such Termination Date and shall otherwise
remain exercisable for their term in
accordance with the terms thereof."
(5) By inserting immediately following Section
8(d) a new Section 8(e) to read as follows:
"(e) If the employment of the Executive is
terminated for any reason after a Change in
Control, then without further action by the
Company, the Board or any committee thereof,
the Executive may exercise any vested stock
options (including vested PASOs) held by the
Executive pursuant to existing procedures
approved by the Stock Option Committee for
cashless exercise, by surrendering previously
owned shares, electing to have the Company
withhold shares otherwise deliverable upon
exercise of such options, or by providing an
irrevocable direction to a broker to sell
shares and deliver all or a portion of the
proceeds to the Company, in any case in an
amount equal to the aggregate exercise price
and any tax withholding obligation attendant
to the exercise."
(6) By inserting immediately following Section 8
a new Section 8A, which shall read in its entirety as
follows:
"Section 8A. Certain Additional Payments by
the Company.
(a) Anything in this Agreement to the
contrary notwithstanding, in the event it shall be
determined that any payment, distribution, waiver
of Company rights, acceleration of vesting of any
stock options or restricted stock, or any other
payment or benefit in the nature of compensation
to or for the benefit of the Executive, alone or
in combination (whether such payment,
distribution, waiver, acceleration or other
benefit is made pursuant to the terms of this
Agreement or any other agreement, plan or
arrangement providing payments or benefits in the
nature of compensation to or for the benefit of
the Executive, but determined without regard to
any additional payments required under this
Section 8A) (a "Payment") would be subject to the
excise tax imposed by Section 4999 of the Code (or
any successor provision) or any interest or
penalties are incurred by the Executive with
respect to such excise tax (such excise tax,
together with any such interest and penalties, are
hereinafter collectively referred to as the
"Excise Tax"), then the executive shall be
entitled to receive an additional payment (a
"Gross-Up Payment") in an amount such that after
payment by the Executive of all taxes with respect
to the Gross-Up Payment (including any interest or
penalties imposed with respect to such taxes),
including, without limitation, any income taxes
(and any interest and penalties imposed with
respect thereto) and Excise Tax imposed upon the
Gross-Up Payment, the Executive retains an amount
of the Gross-Up Payment equal to the Excise Tax
imposed upon the Payments.
(b) Subject to the provisions of Section
8A(c), all determinations required to be made
under this Section 8A, including whether and when
a Gross-Up Payment is required and the amount of
such Gross-Up Payment and the assumptions to be
utilized in arriving at such determination, shall
be made by Deloitte and Touche, LLP, or such other
nationally recognized accounting firm then
auditing the accounts of the Company (the
"Accounting Firm") which shall provide detailed
supporting calculations both to the Company and
the Executive within 15 business days of the
receipt of notice from the Executive that there
has been a Payment, or such earlier time as is
requested by the Company. In the event that the
Accounting Firm is unwilling or unable to perform
its obligations pursuant to this Section 8A, the
Executive shall appoint another nationally
recognized accounting firm to make the
determinations required hereunder (which
accounting firm shall then be referred to
hereunder as the Accounting Firm). All fees and
expenses of the Accounting Firm shall be borne
solely by the Company. Any Gross-Up Payment,
determined pursuant to this Section 8A, shall be
paid by the Company to the Executive within five
days of the receipt of the Accounting Firm's
determination. Any determination by the
Accounting Firm shall be binding upon the Company
and the Executive. The parties hereto acknowledge
that, as a result of the potential uncertainty in
the application of Section 4999 of the Code (or
any successor provision) at the time of the
initial determination by the Accounting Firm
hereunder, it is possible that the Company will
not have made Gross-Up Payments which should have
been made consistent with the calculations
required to be made hereunder (an "Underpayment").
In the event that the Company exhausts its
remedies pursuant to Section 8A(c) and the
Executive thereafter is required to make a payment
of any Excise Tax, the Accounting Firm shall
determine the amount of the Underpayment that has
occurred and any such Underpayment shall be
promptly paid by the Company to or for the benefit
of the Executive.
(c) The Executive shall notify the Company
in writing of any claim by the Internal Revenue
Service that, if successful, would require the
payment by the Company of the Gross-Up Payment.
Such notification shall be given as soon as
practicable but no later than 20 business days
after the Executive is informed in writing of such
claim and shall apprise the Company of the nature
of such claim and the date on which such claim is
requested to be paid. The Executive shall not pay
such claim prior to the expiration of the 30-day
period following the date on which he gives such
notice to the Company (or such shorter period
ending on the date that any payment of taxes with
respect to such claim is due). If the Company
notifies the Executive in writing prior to the
expiration of such period that it desires to
contest such claim, the Executive shall:
(i) give the Company any information reasonably
requested by the Company relating to such
claim,
(ii) take such action in connection with
contesting such claim as the Company shall
reasonably request in writing from time to
time, including, without limitation,
accepting legal representation with respect
to such claim by an attorney reasonably
selected by the Company,
(iii) cooperate with the Company in good faith in
order effectively to contest such claim, and
(iv) permit the Company to participate in any
proceedings relating to such claim;
provided, however, that the Company shall bear and
pay directly all costs and expenses (including
additional interest and penalties) incurred in
connection with such contest and shall indemnify
and hold the Executive harmless, on an after-tax
basis, for any Excise Tax or income tax (including
interest and penalties with respect thereto)
imposed as a result of such representation and
payment of costs and expenses. Without limiting
the foregoing provisions of this Section 8A(c),
the Company shall control all proceedings taken in
connection with such contest and, at its sole
option, may pursue or forgo any and all
administrative appeals, proceedings, hearings and
conferences with the taxing authority in respect
of such claim and may, at its sole option, either
direct the Executive to pay the tax claimed and
sue for a refund or contest the claim in any
permissible manner, and the Executive agrees to
prosecute such contest to a determination before
any administrative tribunal, in a court of initial
jurisdiction and in one or more appellate courts,
as the Company shall determine; provided, however,
that if the Company directs the Executive to pay
such claim and sue for a refund, the Company shall
advance the amount of such payment to the
Executive, on an interest-free basis, and shall
indemnify and hold the Executive harmless, on an
after-tax basis, from any Excise Tax or income tax
(including interest or penalties with respect
thereto) imposed with respect to such advance or
with respect to any imputed income with respect to
such advance; and further provided that any
extension of the statute of limitations relating
to payment of taxes for the taxable year of the
Executive with respect to which such contested
amount is claimed to be due is limited solely to
such contested amount. Furthermore, the Company's
control of the contest shall be limited to issues
with respect to which a Gross-Up Payment would be
payable hereunder and the Executive shall be
entitled to settle or contest, as the case may be,
any other issue raised by the Internal Revenue
Service or any other taxing authority.
(d) If, after the receipt by the Executive
of an amount advanced by the Company pursuant to
Section 8A(c), the Executive becomes entitled to
receive any refund with respect to such claim, the
Executive shall (subject to the Company's
complying with the requirements of Section 8A(c))
promptly pay to the Company the amount of such
refund (together with any interest paid or
credited thereon after taxes applicable thereto).
If, after the receipt by the Executive of an
amount advanced by the Company pursuant to Section
8A(c), a determination is made that the Executive
shall not be entitled to any refund with respect
to such claim and the Company does not notify the
Executive in writing of its intent to contest such
denial of refund prior to the expiration of 30
days after such determination, then such advance
shall be forgiven and shall not be required to be
repaid and the amount of such advance shall
offset, to the extent thereof, the amount of Gross-
Up Payment required to be paid."
Except as provided herein and to the extent
necessary to give full effect to the provisions of this
Amendment, the terms of the Employment Agreement shall
remain in full force and effect.
IN WITNESS WHEREOF, the parties hereto have
entered into this Amendment effective as of April 16, 1997.
CALENERGY COMPANY, INC.
By: /s/ David L. Sokol
Name: David L. Sokol
Title: Chairman of the
Board
EXECUTIVE
/s/ Gregory E. Abel
Gregory E. Abel
Exhibit 10.35
EMPLOYMENT AGREEMENT
This Employment Agreement is entered into as of January 11,
1998, by and between CalEnergy Company, Inc. a Delaware
corporation (the "Company"), and Craig M. Hammett (the
"Executive").
RECITALS
The Company desires to employ the Executive as its Senior
Vice President and Chief Financial Officer on the terms set forth
in this Agreement, and the Executive desires to accept such
employment.
Accordingly, the Company and the Executive agree as follows:
AGREEMENT
Section 1. Defined Terms. Terms used but not defined in
this Agreement will have the meanings ascribed to them in Exhibit
A to this Agreement.
Section 2. Employment.
(a) The Company will employ the Executive as, and the
Executive will act as the Senior Vice President and Chief
Financial Officer of the Company, subject to and upon the terms
set forth in this Agreement, for the Term of Employment.
(b) The Executive's primary place of employment will
be Omaha, Nebraska or such other place as is determined, prior to
a Change in Control, in good faith by the Chairman of the Board
and Chief Executive Officer of the Company (hereinafter referred
to as the "Chairman of the Board") to be in the best interests of
the Company.
Section 3. Duties.
(a) The Executive (i) will perform and discharge the
duties incident to and consistent with his title of Senior Vice
President and Chief Financial Officer, and (ii) will perform and
discharge such other duties, and will have such other authority,
as are delegated to him by the Chairman of the Board. In
performing such duties, the Executive will report directly to,
and be subject to the direction of, the Chairman of the Board.
Prior to a Change in Control, the Executive's title and duties
may in good faith be modified by the Chairman of the Board.
(b) The Executive will act, without any compensation
in addition to the compensation payable pursuant to this
Agreement, as an officer or member of the board of directors of
any subsidiary of the Company, if so appointed or elected.
(c) During the Term of Employment, the Executive (i)
will devote his entire time, attention and energies during normal
business hours to the business of the Company and its
subsidiaries and (ii) will not, without the written consent of
the Chairman of the Board, perform any services for any other
Person or engage in any other business or professional activity,
whether or not performed or engaged in for profit.
(d) Notwithstanding subsection 3(c), the Executive,
without the consent of the Chairman of the Board, may (i)
purchase securities issued by, or otherwise passively invest his
personal or family assets in, any other company or business
within the constraints imposed by the Policy of Business Conduct
referred to below, and (ii) engage in governmental, political,
educational or charitable activities, but only to the extent that
those activities (A) are not inconsistent with any direction of
the Chairman of the Board or any duties under this Agreement, and
(B) do not interfere with the devotion by the Executive of his
entire time, attention and energies during normal business hours
to the business of the Company.
Section 4. Compensation.
(a) During the Term of Employment, the Company will
pay the Executive a base salary at an annual rate of $160,000, in
substantially equal periodic payments in accordance with the
Company's practices for executive employees, as determined from
time to time by the Chairman of the Board.
(b) The Chairman of the Board will review the salary
payable to the Executive at least annually beginning in the
fourth fiscal quarter of 1998. The Chairman of the Board, in his
discretion, may increase the salary of the Executive from time to
time, but may not reduce the salary of the Executive below the
amount set forth in subsection 4(a) above.
(c) During the Term of Employment, the Executive shall
be eligible for consideration for an annual incentive merit
bonus, for the Executive's performance during the preceding
fiscal year of the Company in an amount determined by the
Chairman of the Board in his discretion, by reference to the
accomplishment by the Executive of goals established by the
Chairman of the Board for the related fiscal year.
(d) The Company will reimburse the Executive, subject
to compliance by the Executive with the Company's customary
reimbursement practices, for all reasonable and necessary out-of-
pocket expenses incurred by the Executive on behalf of the
Company in the course of its business.
(e) The Company may reduce any payments made to the
Executive under this Agreement by any required federal, state or
local government withholdings or deductions for taxes or similar
charges, or otherwise pursuant to law, regulation or order.
(f) Any base salary payable to the Executive for any
period of employment of less than one year during the Term of
Employment will be reduced to reflect the actual number of days
of employment during the period except as provided in Sections
8(b) and 8(c).
Section 5. Other Benefits.
(a) During the Term of Employment, the Executive and
his dependents may participate in and receive benefits under any
employee benefit plan which the Company makes generally available
to its employees and their families, including any pension, life
insurance, medical benefits, dental benefits or disability plan,
but only to the extent that the Executive or his dependents
otherwise satisfies the standards established for participation
in the plan. The terms of Executive's existing option agreement,
as amended, remain unaffected hereby, except as set forth in
Section 8(b) and 8(c) hereof.
(b) The Executive may take up to three weeks of
vacation during each full calendar year during the Term of
Employment at a time mutually convenient to the Executive and the
Company, without loss of compensation or other benefits under
this Agreement.
Section 6. Confidentiality and Post-Employment
Restriction.
(a) The Executive acknowledges that the Company and
its Affiliates have confidential information and trade secrets,
whether written or unwritten, with respect to carrying on their
business, including sensitive marketing, bidding, technological
and engineering information and data, names of past, present and
prospective customers or partners of and vendors of suppliers to
the Company and its Affiliates, working relationships with
governmental agencies and officials, methods of pricing contracts
and income and expenses associated therewith, the international
business strategy and relative ranking of opportunities in
various countries, negotiated prices and offers outstanding,
credit terms and status of accounts and the terms of
circumstances of any current or prospective business arrangements
between the Company and its Affiliates and any third parties
("Confidential Information and Trade Secrets"). As used in this
Agreement, the term Confidential Information and Trade Secrets
does not include (i) information which becomes generally
available to the public other than as a result of a disclosure by
the Executive, (ii) information which becomes available to the
Executive on a nonconfidential basis from a source other than the
Company or its Affiliates, or (iii) information known to the
Executive prior to any disclosure to him by the Company or its
Affiliates. The Executive further acknowledges that the
Executive possesses a high degree of knowledge of the independent
energy industry and, in particular, has committed to a long-
standing relationship with the Company and its Affiliates as an
employee and officer, which has allowed, and will continue to
allow, him access to the Company's Confidential Information and
Trade Secrets. Accordingly, any employment by the Executive with
another employer in the independent energy industry or
participation by him as a substantial investor in any such
industry may necessarily involve disclosure of the Company's
Confidential Information and Trade Secrets. Consequently, the
Executive agrees that, if he voluntarily resigns his employment
with the Company for any reason other than (i) a breach of this
Agreement by the Company, or (ii) for Good Reason, he shall not
at any time during the two-year period after such resignation,
directly or indirectly accept employment by or invest in (except
as a passive investor in a public corporation or in a publicly
issued partnership interest which, in either event, would not
exceed an ownership interest of 2% of the outstanding equity or
partnership interest) in any person, firm, corporation,
partnership, joint venture or business which is primarily engaged
in the production or marketing of st4eam or electrical energy or
which otherwise directly competes with the business of the
Company or its controlled Affiliates and, further, the Executive
agrees that, to avoid the risk of disclosing or improperly using
Confidential Information or Trade Secrets, he shall not directly,
or indirectly, provide consulting or advisory services to any of
such independent energy business.
(b) Without the written consent of the Chairman of the
Board, the Executive will not, during and for three years after
the Term of Employment, (i) disclose any Confidential Information
and Trade Secrets of the Company or any Affiliate of the Company
to any Person (other than the Company, directors, officers or
employees of the Company, its Affiliates or duly authorized
agents, attorneys or other representatives thereof), or (ii)
otherwise make use of any Confidential Information and Trade
Secrets other than in connection with authorized dealings with or
by the Company and its Affiliates.
(c) For a period of three years after the Term of
Employment, the Executive shall neither directly nor indirectly
solicit, on behalf of another employer, the employment of, or
hire or cause another employer to hire, any person who is then
currently employed by the Company or an Affiliate thereof, or
otherwise induce, on behalf of another employer, such person to
leave the employment of the Company or an Affiliate thereof
without the prior written approval of the Chairman of the Board.
(d) The Executive will hold, on behalf of the Company
and its Affiliates and as the property of the Company and its
Affiliates, all memoranda, manuals, books, papers, letters,
documents, computer discs, data and software and other similar
property obtained during the course of his employment by the
Company or its Affiliates and relating to the Company's or its
Affiliates business, and will return such property to the Company
or its Affiliates at any time upon demand by the Chairman of the
Board and, in any event, within five calendar days after the end
of the Term of Employment.
(e) During the Term of Employment, Executive agrees to
comply in all material respects with the Company's Policy of
Business Conduct attached hereto as Exhibit A and to deliver with
the execution of this Agreement and executed Certificate of
Compliance with respect thereto.
(f) If any of the provisions of, or covenants
contained in, this Section 6 are hereafter construed to be
invalid or unenforceable in any jurisdiction, the same shall not
affect the remainder of the provisions or the enforceability
thereof in any other jurisdiction, which shall be given full
effect, without regard to the invalidity or unenforceability in
such other jurisdiction. If any of the provisions of, or
covenants contained in, this Section 6 are held to be
unenforceable in any jurisdiction because of the duration or
geographical scope thereof, the parties agree that the court
making such determination shall have the power to reduce the
duration or geographical scope of such provision or covenant and,
in its reduced form, such provision or covenant shall be
enforceable; provided, however, that the determination of such
court shall not affect the enforceability of this Section 6 in
any other jurisdictions.
Section 7. Termination of Employment.
(a) The employment of the Executive under this
Agreement will terminate on the earliest of: (i) written notice
by the Executive of his resignation other than for Good Reason;
(ii) the day the Company gives to the Executive written notice of
termination without Cause; (iii) the day the Company gives to the
Executive written notice of termination for Cause; (iv) the
Permanent Disability of the Executive; (v) the death of the
Executive; or (vi) written notice by the Executive of his
resignation for Good Reason.
(b) If the employment of the Executive is terminated
under this Agreement for any reason whatsoever, the obligations
of the Executive under Section 6 will remain in full force and
effect to the extent provided therein, and the termination will
not abrogate any rights or remedies of the Company or the
Executive with respect to any breach of the Agreement, except as
expressly provided in Section 8.
Section 8. Payment Upon Termination.
(a) If the employment of the Executive is terminated
pursuant to subsections (i) or (iii) of Section 7(a), the Company
will pay to the Executive, within 30 calendar days, any base
salary and reimbursable expenses pursuant to Section 4(a) and
Section 4(d) which are accrued but unpaid through the Termination
Date.
(b) If the employment of the Executive is terminated
pursuant to subsections (ii), (iv) or (v) of Section 7(a) prior
to a Change in Control, the Company will pay the Executive,
subject to the Executive's compliance in all material respects
with his post-termination obligations under Section 6, (i) within
30 calendar days, any base salary and reimbursable expenses which
are accrued and unpaid through such date, (ii) commencing one
month after the month of his Termination Date, 24 monthly
payments each equal to 1/24 of a sum equal to twice his annual
base salary then in effect pursuant to Section 4 and (iii)
commencing one month after the month of his Termination Date, 24
monthly payments each equal to 1/24 of a sum equal to twice the
average of his prior three years incentive bonuses (with any such
year in which no bonus was paid included in such three year
average as a zero). In addition, in the event of any such
termination, subject to the Executive's compliance in all
material respects with his post-termination obligations under
Section 6, the Company agrees that (x) the Company stock options
previously granted to Executive will continue to vest according
to their terms within such next 24 months (beginning with the
month following the month in which the Termination Date occurs,
after which time the unvested remainder will lapse) and such
vested options may be exercised within the remaining term of such
options as provided in the respective option agreements, and (y)
the Company shall continue in effect for Executive, for a period
of twelve months after the date of any such termination, the life
insurance, medical benefits, dental benefits and disability plan
available to the Executive and his dependents on the date of such
termination, subject to such employee contributions and other
terms and conditions as are applicable to active employees
generally and subject to subsequent modification or termination
of such plans to the extent such subsequent actions are also
applicable to active employees generally; provided that such plan
benefits shall terminate earlier on the date, if any, that
comparable benefits are made available to the Executive by any
new employer.
(c) If the employment of the Executive is terminated
on or after a Change in Control pursuant to subsections (ii),
(iv), (v) or (vi) of Section 7(a), the Executive shall receive
the same payments, additional option vesting and benefits
continuation described in Section 8(b) hereof, except that the
monthly payments described in clauses (ii) and (iii) of the first
sentence of Section 8(b) shall be aggregated and paid to
Executive in a single lump sum without any discount to reflect
present value.
(d) Sections 8(b) and 8(c) hereof notwithstanding, in
the event that the payments due to the Executive under this
Agreement, whether alone or together with payments due under any
plan, program, or arrangement maintained by the Company
(collectively, "Payments"), constitute and "excess parachute
payment" (within the meaning of Section 280G(b)(1) of the Code),
the Payments shall be reduced by the minimum possible amount so
that their aggregate present value equals $1.00 less than three
times the Executive's "base amount" (within the meaning of
Section 280G(b)(3)(A) of the Code). The Company's independent
auditors shall determine whether a reduction in Payments shall be
required pursuant to this Section 8(d), and shall determine the
optimal method and order for reduction of Payments so as to
maximize the economic benefits accruing to the Executive in
respect of the Payments.
Section 9. Remedies.
(a) The Company will be entitled, if it elects, to
enjoin any breach or threatened breach of, or enforce the
specific performance of, the obligations of the Executive under
Sections 3 or 6, without showing any actual damage or that
monetary damages would be inadequate. Any such equitable remedy
will not be the sole and exclusive remedy for any such breach,
and the Company may pursue other remedies for such a breach.
(b) Any court proceeding to enforce this Agreement may
be commenced in federal courts, or in the absence of federal
jurisdiction the state courts, located in Omaha, Nebraska. The
parties submit to the jurisdiction of such courts and waive any
objection which they may have to pursuit of any such proceeding
in any such court.
(c) Except to the extent that the Company elects to
seek injunctive relief in accordance with subsection 9(a), any
controversy or claim arising out of or relating to this Agreement
or the validity, interpretation, enforceability or breach of this
Agreement will be submitted to arbitration in Omaha, Nebraska, in
accordance with the then existing rules of the American
Arbitration Association, and judgment upon the award rendered in
any such arbitration may be entered in any court having
jurisdiction.
Section 10. Assignment. Neither the Company nor the
Executive may sell, transfer or otherwise assign their rights, or
delegate their obligations, under this Agreement, provided that
the Company shall require any successor to all or substantially
all of the business, stock or assets of the Company to expressly
assume the Company's rights and obligations hereunder.
Section 11. Unfunded Benefits. All compensation and
other benefits payable to the Executive under this Agreement will
be unfunded, and neither the Company nor any Affiliate of the
Company will segregate any assets to satisfy any obligation of
the Company under this Agreement. The obligations of the Company
to the Executive are not the subject of any guarantee or other
assurance of any Person other than the Company.
Section 12. Severability. Should any provision,
paragraph, clause or portion thereof of this Agreement be
declared or be determined by any court or arbitrator of competent
jurisdiction to be illegal, unenforceable or invalid, the
validity or enforceability of the remaining parts, terms or
provisions shall not be affected thereby and said illegal or
invalid part, term or provisions shall be deemed not to be a part
of this Agreement. Alternatively, the court or arbitrator having
jurisdiction shall have the power to modify such illegal,
unenforceable or invalid provision so that it will be valid and
enforceable, and, in any case, the remaining provisions of this
Agreement shall remain in full force and effect.
Section 13. Miscellaneous.
(a) This Agreement may be amended or modified only by
a writing executed by the Executive and the Company.
(b) This Agreement will be governed by and construed
in accordance with the internal laws of the State of Nebraska.
(c) This Agreement constitutes the entire agreement of
the Company and the Executive with respect to the matters set
forth in this Agreement and supersedes any and all other
agreements between the Company and the Executive relating to
those matters.
(d) Any notice required to be given pursuant to this
Agreement will be deemed given (i) when delivered in person or by
courier or (ii) on the third calendar day after it is sent by
facsimile, with written confirmation of receipt, if to the
Company, to: Chairman of the Board, CalEnergy Company, Inc. at
302 South 36th Street, Suite 400, Omaha, Nebraska 68131, fax
number (402) 231-1658, and, if to the Executive, at 302 South
36th Street, Suite 400, Omaha, Nebraska 68131, fax number (402)
231-1658 or to such other address as may be subsequently
designated by the Company or the Executive in writing to the
other party.
(e) A waiver by a party of a breach of this Agreement
will not constitute a waiver of any other breach, prior or
subsequent, of this Agreement.
IN WITNESS WHEREOF, the Company and the Executive have
entered into this Agreement as of January 11, 1998.
CALENERGY COMPANY, INC.
By: /s/ David L. Sokol
David L. Sokol
Chairman of the Board
EXECUTIVE:
By: /s/ Craig M. Hammett
Craig M. Hammett
EXHIBIT A
Defined Terms
"Affiliate" means, with respect to a Person, (a) any Person
directly or indirectly owning, controlling, or holding power to
vote 10% or more of the outstanding voting securities of the
Person; (b) any Person 10% or more of whose outstanding voting
securities are directly or indirectly owned, controlled or held
with power to vote by the Person; (c) any Person directly or
indirectly controlling, controlled by or under common control
with, the Person; and (d) any officer or director of the Person,
or of any Person directly or indirectly controlling the Person,
controlled by the Person or under common control with the Person.
As used in this definition, "control" means the possession,
directly or indirectly, of the power to direct or cause the
direction of the management and policies of a Person.
"Agreement" means this Employment Agreement dated as of
January 11, 1998, by and between the Company and the Executive,
as it may be amended from time to time in accordance with its
terms.
"Board" means the Board of Directors of the Company.
"Cause" means any or all of the following:
(a) the willful and continued failure by the Executive to
perform substantially the services and duties contemplated
by this Agreement (other than any such failure resulting
from the Executive's incapacity due to disability);
(b) the willful engaging by the Executive in gross misconduct
which is injurious to the business or reputation of the
Company in any material respect;
(c) the gross negligence of the Executive in performing the
services contemplated by this Agreement which is injurious
to the business or reputation of the Company in any material
respect; or
(d) Executive's conviction of, or pleading guilty or no contest
to, a felony involving moral turpitude.
"Change in Control" means (i) approval by the Company's
stockholders of (A) the dissolution of the Company, (B) a merger
or consolidation of the Company where the Company is not the
surviving corporation, except for a transaction the principal
purpose of which is to change the state in which the Company is
incorporated, (C) a reverse merger in which the Company survives
as an entity but in which securities possessing more than 50
percent of the total combined voting power of the Company's
securities are transferred to a person or persons different from
those who hold such securities immediately prior to the merger or
(D) the sale or other disposition of all or substantially all of
the Company's assets; (ii) the direct or indirect acquisition by
any Person or related group of Persons (other than an acquisition
from or by the Company or by a Company-sponsored employee benefit
plan or by a Person that directly or indirectly controls, is
controlled by, or is under common control with, the Company) of
beneficial ownership (within the meaning of Rule 13d-3 of the
Securities Exchange Act of 1934, as amended) of securities
possessing more than 50 percent of the total combined voting
power of the Company's outstanding voting securities; or (iii) a
change in the composition of the Board over a period of thirty-
six (36) months of less such that a majority of the Board members
cease, by reason of one or more contested elections for Board
membership or by one or more actions by written consent of
stockholders, to be comprised of individuals who either (A) have
been Board members continuously since the beginning of such
period or (B) have been elected or nominated for election as
Board members during such period by at least a majority of the
Board members described in clause (A) who were still in office at
the time such election or nomination was approved by the Board.
"Code" means the Internal Revenue Code of 1986, as amended.
"Company" means CalEnergy Company, Inc., a Delaware
corporation, and any successor or assign permitted under the
Agreement.
"Disability" means, with respect to the Executive, that the
Executive has become physically or mentally incapacitated or
disabled so that, in the reasonable judgment of majority of the
Chairman of the Board, he is unable to perform his duties under
this Agreement and such other services as he performed on behalf
of the Company before incurring such incapacity or disability.
"Good Reason" means any of the following events, but only if
such event(s) occur on, after or in connection with a Change in
Control: (i) the failure by the Company to pay to the Executive,
for a material period of time and in a material amount,
compensation due and payable by the Company under Section 4(a) of
this Agreement; (ii) any reduction by the company of the title,
office, duties or authority of the Executive in any material
respect; or (iii) any relocation of the Executive's primary place
of employment to a location more than 25 miles from Omaha,
Nebraska.
"Permanent Disability" means a Disability which has
continued for at least six consecutive calendar months.
"Person" means any natural person, general partnership,
limited partnership, corporation, joint venture, trust, business
trust, or other entity.
"Term of Employment" means the period of time beginning on
January 11, 1998, and ending on the fifth anniversary of such
date, unless earlier terminated pursuant to Section 7(a) or
automatically extended pursuant to the following sentence. The
Term of Employment will be automatically extended for one year on
each anniversary of the date of this Agreement beginning on the
fifth anniversary unless the Executive has given the Company, or
the Company has given the Executive, a notice declining automatic
extension at least 365 calendar days before the anniversary.
"Termination Date" means the date of termination of
employment of the Executive pursuant to Section 7 of this
Agreement.
Exhibit 10.36
AMENDMENT NO. 1
TO THE
EMPLOYMENT AGREEMENT
BETWEEN
CALENERGY COMPANY, INC.
AND
CRAIG M. HAMMETT
This Amendment No. 1 (the "Amendment") to the
Employment Agreement dated January 11, 1998 (the "Employment
Agreement") by and between CalEnergy Company, Inc., a Delaware
corporation (the "Company"), and Craig M. Hammett (the
"Executive"), is entered into as of January 12, 1998.
WHEREAS, the Company and the Executive are presently
parties to the Employment Agreement; and
WHEREAS, the Company and the Executive desire to amend
the Employment Agreement as set forth herein;
NOW, THEREFORE, the Employment Agreement is hereby
amended as follows:
(1) By adding the following sentences at the end of
Section 4(c):
"The Executive shall also be eligible to be paid
other bonuses for each fiscal year as determined by
the Chairman of the Board. The Executive's annual
incentive merit bonus, together with all such other
bonuses paid or payable for the fiscal year
(including any amounts for which receipt is
otherwise deferred pursuant to a plan or
arrangement with the Company), is referred to
herein as `Annual Bonus Compensation.'"
(2) By adding the following sentence after the last
sentence of Section 6(a):
"The preceding sentence notwithstanding, if the
Executive's resignation occurs upon or after a
Change in Control, he shall not be precluded from
accepting employment or providing services to Peter
Kiewit Sons', Inc. or any affiliate thereof."
(3) By deleting from the first sentence of Section
8(b) the language following the parenthetical "(iii)" and
replacing it with the following:
"commencing one month after the month of his
Termination Date, 24 monthly payments each equal to
1/24 of a sum equal to two times the average Annual
Bonus Compensation payable to the Executive in
respect of the two fiscal years immediately
preceding the year in which the Executive's
employment with the Company terminates (with any
such year for which no bonus was payable included
in such two year average as a zero)."
(4) By deleting current Section 8(d) and inserting
new Section 8(d), to read as follows:
"(d) If the employment of the Executive is
terminated pursuant to subsections (ii) or (vi) of
Section 7(a), any Performance Accelerated Stock
Options ("PASOs") held by the Executive on the
Termination Date will become vested and immediately
exercisable on such Termination Date and shall
otherwise remain exercisable for their term in
accordance with the terms thereof." "
(5) By inserting immediately following Section 8(d)
a new Section 8(e) to read as follows:
"(e) If the employment of the Executive is
terminated for any reason after a Change in
Control, then without further action by the
Company, the Board of any committee thereof, the
Executive may exercise any vested stock options
(including any vested PASOs) held by the Executive
pursuant to existing procedures approved by the
Stock Option Committee for cashless exercise, by
surrendering previously owned shares, electing to
have the Company withhold shares otherwise
deliverable upon exercise of such options, or by
providing an irrevocable direction to a broker to
sell shares and deliver all or a portion of the
proceeds to the Company, in any case in an amount
equal to the aggregate exercise price and any tax
withholding obligation attendant to the exercise."
(6) By inserting immediately following Section 8 a new
Section 8A, which shall read in its entirety as follows:
"Section 8A. Certain Additional
Payments by the Company.
(a) Anything in this Agreement to the
contrary notwithstanding, in the event it shall be
determined that any payment, distribution, waiver
of Company rights, acceleration of vesting of any
stock options or restricted stock, or any other
payment or benefit in the nature of compensation to
or for the benefit of the Executive, alone or in
combination (whether such payment, distribution,
waiver, acceleration or other benefit is made
pursuant to the terms of this Agreement or any
other agreement, plan or arrangement providing
payments or benefits in the nature of compensation
to or for the benefit of the Executive, but
determined without regard to any additional
payments required under this Section 8A) (a
"Payment") would be subject to the excise tax
imposed by Section 4999 of the Code (or any
successor provision) or any interest or penalties
are incurred by the Executive with respect to such
excise tax (such excise tax, together with any such
interest and penalties, are hereinafter
collectively referred to as the "Excise Tax"), then
the Executive shall be entitled to receive an
additional payment (a "Gross-Up Payment") in an
amount such that after payment by the Executive of
all taxes with respect to the Gross-Up Payment
(including any interest or penalties imposed with
respect to such taxes), including, without
limitation, any income taxes (and any interest and
penalties imposed with respect thereto) and Excise
Tax imposed upon the Gross-Up Payment, the
Executive retains an amount of the Gross-Up Payment
equal to the Excise Tax imposed upon the Payments.
(b) Subject to the provisions of
Section 8A(c), all determinations required to be
made under this Section 8A, including whether and
when a Gross-Up Payment is required and the amount
of such Gross-Up Payment and the assumptions to be
utilized in arriving at such determination, shall
be made by Deloitte and Touche LLP, or such other
nationally recognized accounting firm then auditing
the accounts of the Company (the "Accounting Firm")
which shall provide detailed supporting
calculations both to the Company and the Executive
within 15 business days of the receipt of notice
from the Executive that there has been a Payment,
or such earlier time as is requested by the
Company. In the event that the Accounting Firm is
unwilling or unable to its obligations pursuant to
this Section 8A, the Executive shall appoint
another nationally recognized accounting firm to
make the determinations required hereunder (which
accounting firm shall then be referred to hereunder
as the Accounting Firm). All fees and expenses of
the Accounting Firm shall be borne solely by the
Company. Any Gross-Up Payment, determined pursuant
to this Section 8A, shall be paid by the Company to
the Executive within five days of the receipt of
the Accounting Firm's determination. Any
determination by the Accounting Firm shall be
binding upon the Company and the Executive. The
parties hereto acknowledge that, as a result of the
potential uncertainty in the application of Section
4999 of the Code (or any successor provision) at
the time of the initial determination by the
Accounting Firm hereunder, it is possible that the
Company will not have made Gross-Up Payments which
should have been made consistent with the
calculations required to be made hereunder (an
"Underpayment"). In the event that the Company
exhausts its remedies pursuant to Section 8A(c) and
the Executive thereafter is required to make a
payment of any Excise Tax, the Accounting Firm
shall determine the amount of the Underpayment that
has occurred and any such Underpayment shall be
promptly paid by the Company to or for the benefit
of the Executive.
(c) The Executive shall notify the Company
in writing of any claim by the Internal Revenue
Service that, if successful, would require the
payment by the Company of the Gross-Up Payment.
Such notification shall be given as soon as
practicable but no later than 20 business days
after the Executive is informed in writing of such
claim and shall apprise the Company of the nature
of such claim and the date on which such claim is
requested to be paid. The Executive shall not pay
such claim prior to the expiration of the 30-day
period following the date on which he gives such
notice to the Company (or such shorter period
ending on the date that any payment of taxes with
respect to such claim is due). If the Company
notifies the Executive in writing prior to the
expiration of such period that it desires to
contest such claim, the Executive shall:
(i) give the Company any
information reasonably requested by the
Company relating to such claim,
(ii) take such action in connection
with contesting such claim as the Company
shall reasonably request in writing from time
to time, including, without limitation,
accepting legal representation with respect
to such claim by an attorney reasonably
selected by the Company,
(iii) cooperate with the Company in
good faith in order effectively to contest
such claim, and
(iv) permit the Company to
participate in any proceedings relating to
such claim;
providing, however, that the Company shall bear
and pay directly all costs and expenses (including
additional interest and penalties) incurred in
connection with such contest and shall indemnify
and hold the Executive harmless, on an after-tax
basis, for any Excise Tax or income tax (including
interest and penalties with respect thereto)
imposed as a result of such representation and
payment of costs and expenses. Without limiting
the foregoing provisions of this Section 8A(c), the
Company shall control all proceedings taken in
connection with such contest and, at its sole
option, may pursue or forgo any and all
administrative appeals, proceedings, hearings and
conferences with the taxing authority in respect of
such claim and may, at its sole option, either
direct the Executive to pay the tax claimed and sue
for a refund or contest and claim in any
permissible manner, and the Executive agrees to
prosecute such contest to a determination before
any administrative tribunal, in a court of initial
jurisdiction and in one or more appellate courts,
as the Company shall determine; provided, however,
that if the Company directs the Executive to pay
such claim and sue for a refund, the Company shall
advance the amount of such payment to the
Executive, on an interest-free basis, and shall
indemnify and hold the Executive harmless, on an
after-tax basis, from any Excise Tax or income tax
(including interest or penalties with respect
thereto) imposed with respect to such advance or
with respect to any imputed income with respect to
such advance; and further provided that any
extension of the statute of limitations relating to
payment of taxes for the taxable year of the
Executive with respect to which such contested
amount is claimed to be due is limited solely to
such contested amount. Furthermore, the Company's
control of the contest shall be limited to issues
with respect to which a Gross-Up Payment would be
payable hereunder and the Executive shall be
entitled to settle or contest, as the case may be,
any other issue raised by the Internal Revenue
Service or any other taxing authority.
(d) If, after the receipt by the
Executive of an amount advanced by the Company
pursuant to Section 8A(c), the Executive becomes
entitled to receive any refund with respect to such
claim, the Executive shall (subject to the
Company's complying with the requirements of
Section 8A(c)) promptly pay to the Company the
amount of such refund (together with any interest
paid or credited thereon after taxes applicable
thereto). If, after the receipt by the Executive
of an amount advanced by the Company pursuant to
Section 8A(c), a determination is made that the
Executive shall not be entitled to any refund with
respect to such claim and the Company does not
notify the Executive in writing of its intent to
contest such denial of refund prior to the
expiration of 30 days after such determination,
then such advance shall be forgiven and shall not
be required to be repaid and the amount of such
advance shall offset, to the extent thereof, the
amount of Gross-Up Payment required to be paid."
Except as provided herein and to the extent necessary
to give full effect to the provisions of this
Amendment, the terms of the Employment Agreement shall remain in
full force and effect.
IN WITNESS WHEREOF, the parties hereto have entered
into this Amendment effective as of January 12,1998.
CALENERGY COMPANY,
INC.
By:/s/ David L. Sokol
Name: David L. Sokol
Title: Chairman of the Board
EXECUTIVE
By:/s/ Craig M. Hammett
Craig M. Hammett
Exhibit 10.38
AMENDMENT NO. 1
TO THE
EMPLOYMENT AGREEMENT
BETWEEN
CALENERGY COMPANY, INC.
AND
STEVEN A. MCARTHUR
This Amendment No. 1 (the "Amendment") to the Employment
Agreement dated August 6, 1996 (the "Employment Agreement") by
and between CalEnergy Company, Inc., a Delaware corporation (the
"Company"), and Steven A. McArthur (the "Executive"), is entered
into as of April 16, 1997.
WHEREAS, the Company and the Executive are presently parties
to the Employment Agreement; and
WHEREAS, the Company and the Executive desire to amend the
Employment Agreement as set forth herein;
NOW, THEREFORE, the Employment Agreement is hereby amended
as follows:
(1) By adding the following sentences at the end of Section
4(c):
"The Executive shall also be eligible to be paid other
bonuses for each fiscal year as determined by the
Chairman of the Board. The Executive's annual
incentive merit bonus, together with all such other
bonuses paid or payable for the fiscal year (including
any amounts for which receipt is otherwise deferred
pursuant to a plan or arrangement with the Company), is
referred to herein as `Annual Bonus Compensation.'"
(2) By adding the following sentence after the last sentence
of Section 6(a):
"The preceding sentence notwithstanding, if the
Executive's resignation occurs upon or after a Change
in Control, he shall not be precluded from accepting
employment or providing services to Peter Kiewit Sons',
Inc. or any affiliate thereof."
(3) By deleting from the first sentence of Section 8(b) the
language following the parenthetical "(iii)" and replacing it
with the following:
"commencing one month after the month of his
Termination Date, 24 monthly payments each equal to
1/24 of a sum equal to two times the average Annual
Bonus Compensation payable to the Executive in respect
of the two fiscal years immediately preceding the year
in which the Executive's employment with the Company
terminates (with any such year for which no bonus was
payable included in such two year average as a zero)."
(4) By deleting current Section 8(d) and inserting new
Section 8(d), to read as follows:
"(d) If the employment of the Executive is terminated
pursuant to subsections (ii) or (vi) of Section 7(a),
all Performance Accelerated Stock Options ("PASOs")
held by the Executive on the Termination Date will
become vested and immediately exercisable on such
Termination Date and shall otherwise remain exercisable
for their term in accordance with the terms thereof."
(5) By inserting immediately following Section 8(d) a new
Section 8(e) to read as follows:
"(e) If the employment of the Executive is terminated
for any reason after a Change in Control, then without
further action by the Company, the Board or any
committee thereof, the Executive may exercise any
vested stock options (including vested PASOs) held by
the Executive pursuant to existing procedures approved
by the Stock Option Committee for cashless exercise, by
surrendering previously owned shares, electing to have
the Company withhold shares otherwise deliverable upon
exercise of such options, or by providing an
irrevocable direction to a broker to sell shares and
deliver all or a portion of the proceeds to the
Company, in any case in an amount equal to the
aggregate exercise price and any tax withholding
obligation attendant to the exercise."
(6) By inserting immediately following Section 8 a new
Section 8A, which shall read in its entirety as follows:
"Section 8A. Certain Additional Payments by the
Company.
(a) Anything in this Agreement to the contrary
notwithstanding, in the event it shall be determined
that any payment, distribution, waiver of Company
rights, acceleration of vesting of any stock options or
restricted stock, or any other payment or benefit in
the nature of compensation to or for the benefit in the
nature of compensation to or for the benefit of the
Executive, alone or in combination (whether such
payment, distribution, waiver, acceleration or other
benefit is made pursuant to the terms of this Agreement
or any other agreement, plan or arrangement providing
payments or benefits in the nature of compensation to
or for the benefit of the Executive, but determined
without regard to any additional payments required
under this Section 8A) (a "Payment") would be subject
to the excise tax imposed by Section 4999 of the Code
(or any successor provision) or any interest or
penalties are incurred by the Executive with respect to
such excise tax (such excise tax, together with any
such interest and penalties, are hereinafter
collectively referred to as the "Excise Tax"), then the
Executive shall be entitled to receive an additional
payment (a "Gross-Up Payment") in an amount such that
after payment by the Executive of all taxes with
respect to the Gross-Up Payment (including any interest
or penalties imposed with respect to such taxes),
including, without limitation, any income taxes (and
any interest and penalties imposed with respect
thereto) and Excise Tax imposed upon the Gross-Up
Payment, the Executive retains an amount of the Gross-
Up Payment equal to the Excise Tax imposed on the
Payments.
(b) Subject to the provisions of Section 8A(c),
all determinations required to be made under this
Section 8A, including whether and when a Gross-Up
Payment is required and the amount of such Gross-Up
Payment is required and the amount of such Gross-Up
Payment and the assumptions to be utilized in arriving
at such determination, shall be made by Deloitte and
Touche LLP, or such other nationally recognized
accounting firm then auditing the accounts of the
Company (the "Accounting Firm") which shall provide
detailed supporting calculations both to the Company
and the Executive within 15 business days of the
receipt of notice from the Executive that there has
been a Payment, or such earlier time as is requested by
the Company. In the event that the Accounting Firm is
unwilling or unable to perform its obligations pursuant
to this Section 8A, the Executive shall appoint another
nationally recognized accounting firm to make the
determinations required hereunder (which accounting
firm shall then be referred to hereunder as the
Accounting Firm). All fees and expenses of the
Accounting Firm shall be borne solely by the Company.
Any Gross-Up Payment, determined pursuant to this
Section 8A, shall be paid by the Company to the
Executive within five days of the receipt of the
Accounting Firm's determination. Any determination by
the Accounting Firm shall be binding upon the Company
and the Executive. The parties hereto acknowledge
that, as a result of the potential uncertainty in the
application of Section 4999 of the Code (or any
successor provision) at the time of the initial
determination by the Accounting Firm hereunder, it is
possible that the Company will not have made Gross-Up
Payments which should have been made consistent with
the calculations required to be made hereunder (an
"Underpayment"). In the event that the Company
exhausts its remedies pursuant to Section 8A(c) and the
Executive thereafter is required to make a payment of
any Excise Tax, the Accounting Firm shall determine the
amount of the Underpayment that has occurred and any
such Underpayment shall be promptly paid by the Company
to or for the benefit of the Executive.
(c) The Executive shall notify the Company in
writing of any claim by the Internal Revenue Service
that, if successful, would require the payment by the
Company of the Gross-Up Payment. Such notification
shall be given as soon as practicable but no later than
20 business days after the Executive is informed in
writing of such claim and shall apprise the Company of
the nature of such claim and the date on which such
claim is requested to be paid. The Executive shall not
pay such claim prior to the expiration of the 30-day
period following the date on which he gives such notice
to the Company (or such shorter period ending on the
date that any payment of taxes with respect to such
claim is due). If the Company notifies the Executive
in writing prior to the expiration of such period that
it desires to contest such claim, the Executive shall:
(i) give the Company any information reasonably
requested by the Company relating to such claim,
(ii) take such action in connection with contesting
such claim as the Company shall reasonably
request in writing from time to time, including,
without limitation, accepting legal
representation with respect to such claim by an
attorney reasonably selected by the Company,
(iii) cooperate with the Company in good faith in
order effectively to contest such claim, and
(iv) permit the Company to participate in any
proceedings relating to such claim;
provided, however, that the Company shall bear and pay
directly all costs and expenses (including additional
interest and penalties) incurred in connection with
such contest and shall indemnify and hold the Executive
harmless, on an after-tax basis, for any Excise Tax or
income tax (including interest and penalties with
respect thereto) imposed as a result of such
representation and payment of costs and expenses.
Without limiting the foregoing provisions of this
Section 8A(c), the Company shall control all
proceedings taken in connection with such contest and,
at its sole option, may pursue or forgo any and all
administrative appeals, proceedings, hearings and
conferences with the taxing authority in respect of
such claim and may, at its sole option, either direct
the Executive to pay the tax claimed and sue for a
refund or contest the claim in any permissible manner,
and the Executive agrees to prosecute such contest to a
determination before any administrative tribunal, in a
court of initial jurisdiction and in one or more
appellate courts, as the Company shall determine;
provided, however, that if the Company directs the
Executive to pay such claim and sue for a refund, the
Company shall advance the amount of such payment to the
Executive, on an interest-free basis, and shall
indemnify and hold the Executive harmless, on an after-
tax basis, from any Excise Tax or income tax (including
interest or penalties with respect thereto) imposed
with respect to such advance or with respect to any
imputed income with respect to such advance; and
further provided that any extension of the statute of
limitations relating to payment of taxes for the
taxable year of the Executive with respect to which
such contested amount is claimed to be due is limited
solely to such contested amount. Furthermore, the
Company's control of the contest shall be limited to
issues with respect to which a Gross-Up Payment would
be payable hereunder and the Executive shall be
entitled to settle or contest, as the case may be, any
other issue raised by the Internal Revenue Service or
any other taxing authority.
(d) If, after the receipt by the Executive of an
amount advanced by the Company pursuant to Section
8A(c), the Executive becomes entitled to receive any
refund with respect to such claim, the Executive shall
(subject to the Company's complying with the
requirements of Section 8A(c)) promptly pay to the
Company the amount of such refund (together with any
interest paid or credited thereon after taxes
applicable thereto). If, after the receipt by the
Executive of an amount advanced by the Company pursuant
to Section 8A(c), a determination is made that the
Executive shall not be entitled to any refund with
respect to such claim and the Company does not notify
the Executive in writing of its intent to contest such
denial of refund prior to the expiration of 30 days
after such determination, then such advance shall be
forgiven and shall not be required to be repaid and the
amount of such advance shall offset, to the extent
thereof, the amount of Gross-Up Payment required to be
paid."
Except as provided herein and to the extent necessary to
give full effect to the provisions of this Amendment, the terms
of the Employment Agreement shall remain in full force and
effect.
IN WITNESS WHEREOF, the parties hereto have entered into
this Amendment effective as of April 16, 1997.
CALENERGY COMPANY, INC.
By: /s/ David L. Sokol
Name: David L. Sokol
Title: Chairman of the Board
EXECUTIVE
/s/ Steven A. McArthur
Steven A. McArthur
Exhibit 13
Financial Summary
Over the last three years ended December 31, 1997, CalEnergy
Company, Inc. ("CalEnergy" or the "Company") has experienced
significant growth. Revenues have risen at a compound annual
rate of 130% from approximately $186 million in 1994 to
approximately $2,271 million in 1997 and net income available to
common stockholders excluding non-recurring and extraordinary
items has risen at a compound annual rate of 60% from
approximately $33.8 million in 1994 to approximately $138.8
million in 1997. This significant growth has been achieved
through: (i) acquisitions that complement and diversify the
Company's existing business, broaden the geographic locations of
its assets and enhance its competitive capabilities; (ii)
enhancement of the financial and technical performance of
existing and acquired projects; and (iii) development and
construction of new plants.
On September 11, 1997, the Company signed a definitive agreement
with Kiewit Diversified Group ("KDG"), a wholly owned subsidiary
of Peter Kiewit Sons', Inc. ("PKS"), for the Company to purchase
KDG's ownership interest in various project partnerships and
CalEnergy common shares (the "KDG Acquisition"). Accordingly,
common stock and options subject to redemption have been
reclassified in the consolidated balance sheet.
KDG's ownership interest in CalEnergy comprised 20,231,065 shares
of common stock (assuming exercise by KDG of one million options
to purchase CalEnergy shares), the 30% interest in Northern
Electric plc ("Northern"), as well as the following minority
project interests: Mahanagdong (45%), Casecnan (35%), Dieng
(47%), Patuha (44%) and Bali (30%) and other interests in
international development stage projects.
CalEnergy paid approximately $1,159 million for the KDG
Acquisition and final closing of the transaction occurred in
January 1998. CalEnergy funded this acquisition with available
cash and the net proceeds of the equity and senior note offerings
completed in October 1997.
On December 24, 1996, CE Electric plc ("CE Electric"), which in
1997 was 70% owned indirectly by the Company and 30% owned
indirectly by PKS, acquired majority ownership of the outstanding
ordinary share capital of Northern pursuant to a tender offer
(the "Northern Tender Offer") commenced in the United Kingdom on
November 5, 1996. As of March 18, 1997, CE Electric effectively
owned 100% of Northern's ordinary shares.
In the last three years, the Company has consummated three other
significant acquisitions, in addition to the acquisition of
Northern. In January 1995, the Company acquired Magma Power
Company ("Magma"), a publicly-traded United States independent
power producer with 228 megawatts ("MW") of aggregate net
operating capacity and 154 MW of aggregate net ownership
capacity, for approximately $958 million. In April 1996, the
Company completed the buy-out for approximately $70 million of
its partner's interests ("Partnership Interest") in four electric
generating plants in Southern California, resulting in sole
ownership of the Imperial Valley Project. In August 1996, the
Company acquired Falcon Seaboard Resources, Inc. ("Falcon
Seaboard") for approximately $226 million, thereby acquiring
significant ownership in 520 MW of natural gas-fired electric
production facilities located in New York, Texas and Pennsylvania
and a related gas transmission pipeline.
The Company has substantially completed constructing the Dieng
Unit I, 55 net MW geothermal project in Indonesia, which is the
first unit of 400 MW under contract at Dieng. In 1997, the
Company financed and commenced construction of two other
projects; the Dieng Unit II 80 MW project as well as the Patuha
Unit I 80 MW project, which is the first unit of 400 MW under
contract at Patuha. Additionally, the Company has conducted
infrastructure construction and drilling activities for the 400
MW Bali project. Although the Company intends to enforce its
contractual rights, the ultimate outcome of the current uncertain
situation in Indonesia with respect to the possible abrogation by
the Indonesian government of the Dieng, Patuha and Bali contracts
adds significant risk to the completion of those projects and
resulted in the Company recording an asset impairment charge in
the fourth quarter of 1997. This $87 million charge includes all
reasonably estimated asset valuation impairments associated with
the Company's assets in Indonesia and gives effect to the
political risk insurance on such investment.
SELECTED Financial Data
Dollars in Thousands, Except Per Share Amounts
Year Ended December 31,
1997 1996(1) 1995(2) 1994 1993
Income Statement Data:
Operating revenue $2,166,338 $518,934 $335,630 $154,562 $132,059
Total revenue 2,270,911 576,195 398,723 185,854 149,253
Expenses 2,074,051 435,791 301,672 130,018 87,995
Income before provision
for income taxes 196,860(3) 140,404 97,051 55,836 61,258
Minority interest 45,993 6,122 3,005 --- ---
Income before change in accounting
principle and
extraordinary item 51,823(3) 92,461 63,415 38,834 43,074
Cumulative effect of change in
accounting principle --- --- --- --- 4,100
Extraordinary item (135,850) --- --- (2,007) ---
Net income (loss) (84,027)(3) 92,461 63,415 36,827 47,174
Preferred dividends --- --- 1,080 5,010 4,630
Net income (loss) available to
common stockholders (84,027)(3) 92,461 62,335 31,817 42,544
Income per share before change in accounting
principle and
extraordinary item 0.77(3) 1.69 1.32 1.02 1.08
Cumulative effect of change in accounting
principle per share --- --- --- --- 0.12
Extraordinary item per share (2.02) --- --- (0.06) ---
Net income (loss) per share (1.25)(3) 1.69 1.32 0.96 1.20
Balance Sheet Data:
Total assets 7,487,626 5,630,156 2,654,038 1,131,145 715,984
Total liabilities 5,282,162 4,181,052 2,084,474 867,703 425,393
Company-obligated mandatorily
redeemable convertible
preferred securities of
subsidiary trusts 553,930 103,930 --- --- ---
Preferred securities of
subsidiary 56,181 136,065 --- --- ---
Minority interest 134,454 299,252 --- --- ---
Redeemable preferred stock --- --- --- 63,600 58,800
Stockholders' equity 765,326 880,790 543,532 179,991 211,503
1 Reflects the acquisitions of Northern, Falcon Seaboard and the
Partnership Interest owned for a portion of the
year. See Note 4 to the financial statements.
2 Reflects the acquisition of Magma owned for a portion of the
year.
3 Includes the $87,000, $1.29 per share, non-recurring asset
impairment charge.
MANAGEMENT'S Discussion and Analysis of Financial Condition
and Results of Operations
Dollars, Pounds and Shares in Thousands, Except Per Share Amounts
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. The Company's
actual results in the future could differ significantly from the
Company's historical results.
Acquisitions
On December 24, 1996, CE Electric plc ("CE Electric"), which in
1997 was 70% owned indirectly by the Company and 30% owned
indirectly by Peter Kiewit Sons', Inc. ("PKS"), acquired majority
ownership of the outstanding ordinary share capital of Northern
Electric plc ("Northern") pursuant to a tender offer (the
"Northern Tender Offer") commenced in the United Kingdom on
November 5, 1996. As of March 18, 1997, CE Electric effectively
owned 100% of Northern's ordinary shares.
In the last three years, the Company has consummated three other
significant acquisitions, in addition to the acquisition of
Northern. In January 1995, the Company acquired Magma Power
Company ("Magma"), a publicly-traded United States independent
power producer with 228 megawatts ("MW") of aggregate net
operating capacity and 154 MW of aggregate net ownership
capacity, for approximately $958,000. In April 1996, the Company
completed the buy-out for approximately $70,000 of its partner's
interests ("Partnership Interest") in four electric generating
plants in Southern California, resulting in sole ownership of the
Imperial Valley Project. In August 1996, the Company acquired
Falcon Seaboard Resources, Inc. ("Falcon Seaboard") for
approximately $226,000, thereby acquiring significant ownership
in 520 MW of natural gas-fired electric production facilities
located in New York, Texas and Pennsylvania and a related gas
transmission pipeline.
Power Generation Projects
For purposes of consistency in financial presentation, plant
capacity factors for Navy I, Navy II, and BLM plants
(collectively the "Coso Project"), are based upon a nominal
capacity amount of 80 net MW for each plant. Plant capacity
factors for Vulcan, Hoch (Del Ranch), Elmore, Leathers plants
(collectively the "Partnership Project"), are based on nominal
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 Project"), are based on
nominal capacity amounts of 10, 20, 49.8 and 39.6 net MW,
respectively (the Partnership Project and the Salton Sea Project
are collectively referred to as the "Imperial Valley Project").
Plant capacity factors for Saranac, Power Resources, NorCon and
Yuma plants (collectively the "Gas Plants") are based on capacity
amounts of 240, 200, 80 and 50 net MW, respectively. Each plant
possesses an operating margin which allows for production in
excess of the amount listed above. Utilization of this operating
margin is based upon a variety of factors and can be expected to
vary throughout the year under normal operating conditions.
See Note 5 to the financial statements for a discussion of the
Company's significant operating contracts.
Results of Operations Three Years Ended December 31, 1997, 1996
and 1995
Operating revenues increased to $2,166,338 in the year ended
December 31, 1997, from $518,934 in the year ended December 31,
1996, a 317.5% increase. This growth was primarily due to the
acquisitions of Northern, Falcon Seaboard, and the Partnership
Interest as well as the commencement of earnings at Salton Sea
IV, Upper Mahiao and Malitbog.
The increase in operating revenues in 1996 to $518,934 from
$335,630 in 1995 was primarily due to the acquisitions of the
Partnership Interest, Falcon Seaboard and Northern, the deemed
completion and commencement of receipt of revenue from Upper
Mahiao and Unit I of the Malitbog Project in the Philippines, the
completion and commencement of commercial operation of Salton Sea
IV and an increase in the Coso Project's electricity revenues.
The following data represents the supply and distribution
operations at Northern:
1997 1996 1995
Supply (GWh) 14,389 14,185 14,253
Distribution (GWh) 15,714 15,656 15,260
Gas Therms Supply (in thousands) 74.5 50.0 35.3
The increase in units supplied and distributed in 1997 from 1996
reflects increased activity in the local economy. The increase in
therms supplied in 1997 from 1996 reflects the increased volume
as the gas business in the U.K. begins to open up to competition
as a result of regulatory changes.
The following operating data represents the aggregate capacity
and electricity production of the domestic geothermal projects:
1997 1996 1995
Overall capacity factor 101.4% 104.4% 104.8%
kWh produced (in thousands) 4,507,500 4,502,200 4,296,010
Capacity NMW (average) 507.4 491.0* 467.8
* Weighted average for the commencement of operations at the
Salton Sea IV in 1996.
The capacity factor was 100.4% in the fourth quarter of 1997
compared to 102.6%, 99.6% and 103.1% for the third, second and
first quarters of 1997, respectively. The capacity factor
decreased in 1997 from 1996 due to marginally decreasing
production at the Coso Project and a scheduled turbine overhaul
at BLM in April 1997.
The following operating data represents the aggregate capacity
and electricity production of the Gas Plants:
1997 1996 1995
Overall capacity factor 84.3% 84.2% 88.8%
kWh produced (in thousands) 4,211,030 4,216,800 4,433,900
Installed capacity NMW 570 570 570
The capacity factor of the Gas Plants reflects the effect of
certain contractual curtailments. The capacity factors adjusted
for these contractual curtailments are 95.7%, 93.2% and 96.8% for
1997, 1996 and 1995, respectively.
Electric sale price per kWh for the Coso Project, Partnership
Project and Salton Sea Project varies seasonally in accordance
with the rate schedule referenced in the SO4 agreements and power
purchase agreements. The Coso Project's, Partnership Project's
and Salton Sea Project's average electricity prices per kWh
received in 1997, 1996 and 1995 were comprised of (in cents):
Coso Project Energy Capacity & Bonus Total
Average fiscal 1997 12.56 1.91 14.47
Average fiscal 1996 12.61 1.82 14.43
Average fiscal 1995 11.81 1.82 13.63
Partnership Project Energy Capacity & Bonus Total
Average fiscal 1997 10.96 2.18 13.14
Average fiscal 1996 10.02 2.12 12.14
Average fiscal 1995 11.14 2.10 13.24
Salton Sea Project Energy Capacity & Bonus Total
Average fiscal 1997 8.66 1.97 10.63
Average fiscal 1996 8.84 2.29 11.13
Average fiscal 1995 9.50 2.33 11.83
Interest and other income increased in 1997 to $104,573 from
$57,261 in 1996, an 82.6% increase. This increase was due
primarily to interest earned by Northern, equity earnings from
Saranac and Mahanagdong, and increased interest income on the
proceeds of the equity and senior note offerings in October 1997.
Interest and other income decreased in 1996 to $57,261 from
$63,093 in 1995.
Overall, the Company's expenses increased in 1997 due to the full
year of operations of Northern, Falcon Seaboard, Partnership
Interest, Salton Sea IV Project, Upper Mahiao Project and Unit I
of the Malitbog Project and the deemed completion of Units II and
III of the Malitbog Project in July 1997.
Cost of sales increased to $1,055,195 in 1997 from $31,840 in
1996. This increase is a result of reflecting a full year of
Northern's operations. Cost of sales represents Northern's costs
of electricity and appliances during the period of the Company's
controlling interest since December 24, 1996.
Operating expense increased to $345,833 in 1997 from $132,655 in
1996, an increase of 160.7%. This increase is a result of the
acquisitions of Northern, Falcon Seaboard and the Partnership
Interest as well as the commencement of receipt of revenue at
Salton Sea IV, Upper Mahiao and Malitbog. Operating expense
increased to $132,655 in 1996 from $103,602 in 1995, an increase
of 28.0%. The increase is a result of the Falcon Seaboard and the
Partnership Interest acquisitions, and the commencement of
operations of the Salton Sea IV Project.
General and administration costs increased to $52,705 in 1997
from $21,451 in 1996, an increase of 145.7%. This increase is
primarily a result of the addition of Northern. General and
administration costs decreased to $21,451 in 1996 from $23,376
in 1995, a decrease of 8.2%. This decrease is a result of the
Company's continued efforts to reduce costs and reflects the
elimination of redundant functions subsequent to the acquisition
of Magma.
Depreciation and amortization increased to $276,041 in 1997 from
$118,586 in 1996, an increase of 132.8%. This increase is a
result of the acquisitions of Northern, Falcon Seaboard and the
Partnership Interest as well as the commencement of the receipt
of revenue at Salton Sea IV, Upper Mahiao and Malitbog.
Depreciation and amortization increased in 1996 to $118,586 from
$72,249 in 1995, a 64.1% increase. This increase is primarily due
to the Magma, Partnership Interest and Falcon Seaboard
acquisitions, and the commencement of the receipt of revenue at
Salton Sea IV, Upper Mahiao and Malitbog.
Loss on equity investment in the Casecnan Project reflects the
Company's share of interest expense in excess of capitalized
interest and interest income at the Casecnan Project, which is
currently in construction.
Interest expense, less amounts capitalized, increased in 1997 to
$251,305 from $126,038 in 1996, a 99.4% increase, and increased
to $126,038 in 1996 from $102,083 in 1995, a 23.5% increase.
Higher interest expense is primarily due to a larger portfolio of
facilities and their associated debt partially offset by the
increase in capitalized interest on the Company's international
and domestic projects.
The non-recurring charge of $87,000 represents an asset valuation
impairment under Financial Accounting Standard No. 121,
"Accounting for the Impairment of Long-Lived Assets", relating to
CalEnergy's assets in Indonesia. The charge includes all
reasonably estimated cash flows associated with the Company's
assets in Indonesia and gives effect to the political risk
insurance on such investments. The estimate assumes there will
be no tax benefits associated with the asset valuation
impairment.
The provision for income taxes increased to $99,044 in 1997 from
$41,821 in 1996 and $30,631 in 1995. After adjusting for the non-
recurring charge for asset valuation impairment and the dividends
on convertible preferred securities, the effective tax rate was
38.0%, 30.8%, and 31.6% in 1997, 1996, and 1995, respectively.
The increase from 1996 to 1997 is due primarily to larger energy
tax credits and depletion deductions in 1996.
Minority interest increased to $45,993 in 1997 from $6,122 in
1996, an increase of 651.3%. Minority interest consists of
dividends on convertible preferred securities of subsidiary
trusts and the Company's partial ownership in Northern. This
increase is a result of issuance of the $180,000 of Trust II
Securities in February 1997 and $270,000 of Trust III Securities
in August 1997 and a full year of operations from Northern.
Minority interest in 1995 reflects the Company's partial
ownership in Magma for the period from January 10, 1995 to
February 24, 1995.
Income before extraordinary item was $51,823 or $0.77 per common
share in 1997 compared to $92,461 or $1.69 per common share in
1996 and $62,335 or $1.32 per common share in 1995. Excluding
the $87,000, $1.29 per share, non-recurring charge, income before
extraordinary item would have been $138,823 in 1997.
On July 31, 1997, the Finance Act in the United Kingdom was
passed by Parliament and included the introduction of a one time
so-called "windfall tax" equal to 23% of the difference between
the price paid for Northern upon privatization and the Labour
government's assessed "value" of Northern as calculated by
reference to a formula set forth in the July budget. This
amounted to $135,850, net of minority interest, which was
recorded as an extraordinary item. The first installment was
paid on December 1, 1997 and the second installment is payable on
December 1, 1998.
Liquidity and Capital Resources
Cash and short-term investments were $1,446,620 at December 31,
1997 as compared to $429,421 at December 31, 1996. In addition,
the Company's share of joint venture cash and investments
retained in project control accounts was $6,072 and $47,764 at
December 31, 1997 and 1996, respectively. Distributions out of
the project control accounts are made monthly to the Company for
operation and maintenance and capital costs and semiannually to
each Coso Project partner for profit sharing under a prescribed
calculation subject to mutual agreement by the partners. In
addition, the Company recorded separately restricted cash of
$223,636 and $106,968 at December 31, 1997 and 1996,
respectively. The restricted cash balances are comprised
primarily of amounts deposited in restricted accounts from which
the Company will fund construction of Dieng Unit II and Patuha
Unit I; the Power Resources Project, the Upper Mahiao Project and
the Malitbog Project cash reserves for the debt service reserve
funds; and the Coso Project royalty payment.
The Company repurchased 1,622 common shares during 1997 for the
aggregate amount of $55,505. The Company repurchased 472 shares
of common stock in 1996 at an aggregate amount of $12,008. As of
December 31, 1997 the Company held 1,658 shares of treasury stock
at a cost of $56,525 to provide shares for issuance under the
Company's employee stock option and share purchase plan and other
outstanding convertible securities. The repurchase plan minimizes
the dilutive effect of the additional shares issued under these
plans.
On September 11, 1997, the Company signed a definitive agreement
with Kiewit Diversified Group ("KDG"), a wholly owned subsidiary
of PKS, for the Company to purchase KDG's ownership interest in
various project partnerships and CalEnergy common shares (the
"KDG Acquisition").
KDG's ownership interest in CalEnergy comprised approximately
20,231 shares of common stock (assuming exercise by KDG of one
million options to purchase CalEnergy shares), the 30% interest
in Northern Electric, as well as the following minority project
interests: Mahanagdong (45%), Casecnan (35%), Dieng (47%),
Patuha (44%) and Bali (30%) and other interests in international
development projects.
CalEnergy paid $1,159,215 for the KDG Acquisition and final
closing of the transaction occurred in January 1998. CalEnergy
funded this acquisition with available cash and the proceeds of
the equity and senior note offerings completed in October 1997.
On December 15, 1997, CE Electric UK Funding Company, an indirect
subsidiary of the Company (the "Funding Company"), issued
$125,000 of 6.853% senior notes due 2004, and $237,000 of 6.995%
senior notes due 2007 (collectively, the "CE Electric UK Funding
Company Senior Notes"), and pound 200,000 of 7.25% Sterling Bonds due
2022.
On November 26, 1997, the Company amended and increased its
$100,000 revolving credit facility to $400,000. The facility is
unsecured and is available to fund working capital requirements
and finance future business expansion opportunities.
On October 17, 1997, the Company completed the public offering of
17.1 million shares of its common stock ("Common Stock") at $37
7/8 per share (the "Public Offering"). In addition, 2 million
shares of Common Stock were purchased from CalEnergy in a direct
sale by a trust affiliated with Walter Scott, Jr., the Chairman
and Chief Executive Officer of PKS (the "Direct Sale"),
contemporaneously with the closing of the Public Offering.
On October 28, 1997, the Company completed the sale of $350,000
aggregate principal amount of its 7.63% Senior Notes due 2007
(the "Senior Note Offering").
On August 12, 1997, a subsidiary of the Company completed a
private placement (with certain shelf registration rights) of
$225,000 aggregate amount of 6 1/2% Trust Convertible Preferred
Securities (the "6 1/2% Trust Securities"). In addition, an
option to purchase an additional 900 of the 6 1/2% Trust
Securities, or $45,000 aggregate amount, was exercised by the
initial purchasers to cover overallotments in connection with the
placement. Each 6 1/2% Trust Security has a liquidation
preference of fifty dollars and is convertible at any time at the
option of the holder into 1.047 shares of Company Common Stock
(equivalent to a conversion price of $47.75 per common share)
subject to adjustments in certain circumstances.
On August 5, 1997, the Company and certain affiliated capital
funding trusts filed with the Securities and Exchange Commission
a shelf registration statement covering up to $1,500,000 of
common stock, preferred stock and debt securities which may be
sold from time to time for various purposes. The Company
completed the Public Offering and the Senior Note Offering under
the shelf registration statement.
On February 26, 1997, a subsidiary of the Company completed a
private placement (with certain shelf registration rights) of
$150,000 aggregate amount of 6 1/4% Trust Convertible Preferred
Securities ("Trust Securities"). In addition, an option to
purchase an additional 600 Trust Securities, or $30,000 aggregate
amount, was exercised by the initial purchasers to cover over-
allotments in connection with the placement. Each Trust Security
has a liquidation preference of fifty dollars and is convertible
at any time at the option of the holder into 1.1655 shares of
Company Common Stock (equivalent to a conversion price of $42.90
per common share) subject to adjustments in certain
circumstances.
In November 1995, the Company closed the financing and commenced
construction of the Casecnan Project, a combined irrigation and
150 net MW hydroelectric power generation project (the "Casecnan
Project") located in the central part of the island of Luzon in
the Republic of the Philippines.
CE Casecnan Water and Energy Company, Inc., a Philippine
Corporation ("CE Casecnan") which is approximately 70% indirectly
owned by the Company (after the KDG Acquisition), is developing
the Casecnan Project. CE Casecnan financed a portion of the costs
of the Casecnan Project through the issuance of $125,000 of its
11.45% Senior Secured Series A Notes due 2005 and $171,500 of its
11.95% Senior Secured Series B Bonds due 2010 and $75,000 of its
Secured Floating Rate Notes due 2002, pursuant to an indenture
dated as of November 27, 1995, as amended to date.
The Casecnan Project was being constructed pursuant to a fixed-
price, date-certain, turnkey construction contract (the "Hanbo
Contract") on a joint and several basis by Hanbo Corporation
("Hanbo") and Hanbo Engineering and Construction Co., Ltd.
("HECC"), both of which are South Korean corporations. As of May
7, 1997, CE Casecnan terminated the Hanbo Contract due to
defaults by Hanbo and HECC including the insolvency of each such
company. On May 7, 1997, CE Casecnan entered into a new turnkey
engineering, procurement and construction contract to complete
the construction of the Casecnan Project (the "Replacement
Contract"). The work under the Replacement Contract is being
conducted by a consortium consisting of Cooperativa Muratori
Cementisti CMC di Ravenna and Impressa Pizzarottie & C. Spa,
working together with Siemens A.G., Sulzer Hydro Ltd., Black &
Veatch and Colenco Power Engineering Ltd. (collectively, the
"Replacement Contractor").
In connection with the Hanbo Contract termination, CE Casecnan
tendered a certificate of drawing to Korea First Bank ("KFB") on
May 7, 1997, under the irrevocable standby letter of credit
issued by KFB as security under the Hanbo Contract to pay for
certain transition costs and other presently ascertainable
damages under the Hanbo Contract. As a result of KFB's wrongful
dishonor of the draw request, CE Casecnan filed an action in New
York State Court. That Court granted CE Casecnan's request for a
temporary restraining order requiring KFB to deposit $79,329, the
amount of the requested draw, in an interest bearing account with
an independent financial institution in the United States. KFB
appealed this order, but the appellate court denied KFB's appeal
and on May 19, 1997, KFB transferred funds in the amount of
$79,329 to a segregated New York bank account pursuant to the
Court order.
On August 6, 1997, CE Casecnan announced that it had issued a
notice to proceed to the Replacement Contractor. The Replacement
Contractor has fully mobilized and commenced engineering,
procurement and construction work on the Casecnan Project.
On August 27, 1997, CE Casecnan announced that it had received a
favorable summary judgment ruling in New York State Court against
KFB. The judgment, which has been appealed by the bank, requires
KFB to honor the $79,329 drawing by CE Casecnan on a $117,850
irrevocable standby letter of credit.
On September 29, 1997, CE Casecnan tendered a second certificate
of drawing for $10,828 to KFB and on December 30, 1997 CE
Casecnan tendered a third certificate of drawing for $2,920 to
KFB. KFB also wrongfully dishonored these draws, but pursuant to
a stipulation agreed to deposit the draw amounts in an interest
bearing account with the same independent financial institution
in the United States pending resolution of the appeal regarding
the first draw and agreed to expedite the appeal.
The receipt of the letter of credit funds from KFB remains
essential and CE Casecnan will continue to press KFB to honor its
clear obligations under the letter of credit and to pursue Hanbo
and KFB for any additional damages arising out of their actions
to date. If KFB were to fail to honor its obligations under the
Casecnan letter of credit, such action could have a material
adverse effect on the Casecnan Project and CE Casecnan.
On September 2, 1997, Hanbo and HECC filed a Request for
Arbitration before the International Chamber of Commerce ("ICC").
The Request for Arbitration asserts various claims by Hanbo and
HECC against CE Casecnan relating to the terminated Hanbo
Contract and seeking damages. On October 10, 1997, CE Casecnan
served its answer and defenses in response to the Request for
Arbitration as well as counterclaims against Hanbo and HECC for
breaches of the Hanbo Contract. The arbitration proceedings
before the ICC are ongoing and CE Casecnan intends to pursue
vigorously its claims against Hanbo, HECC and KFB in the
proceedings described above.
In June 1997, the Company's indirect special-purpose subsidiary,
CE Indonesia Funding Corp., entered into a $400,000 revolving
credit facility (which is nonrecourse to the Company) to finance
the development and construction of the Company's geothermal
power facilities in Indonesia.
On September 20, 1997, a Presidential Decree (the "Decree") was
issued in Indonesia, providing for government action to the
effect that, in order to address certain recent fluctuations in
the value of the Indonesian currency, the start-up dates for a
number of private power projects would be: (i) continued
according to their initial schedule (because construction was
underway); (ii) postponed as to their start-up dates (because
they are not yet in construction) until economic conditions have
recovered; or (iii) reviewed with a view to being continued,
postponed or rescheduled, depending on the status of those
projects. In the Decree, Dieng Units 1, 2 and 3 are approved to
continue according to their initial schedule; Patuha Unit 1 and
Bali Units 1 and 2 are to receive further review to determine
whether or not they should be continued in accordance with their
initial schedule; and Bali Units 3 and 4, Patuha Units 2, 3 and 4
and Dieng Unit 4 are to be postponed for an unspecified period.
In this regard, the Company notes that its contracts and
government undertakings for the Dieng, Patuha and Bali projects
do not by their terms permit such categorization or delays by the
government and that the Company has obtained political risk
insurance coverage for its Dieng and Patuha projects. Moreover,
the Company intends to continue to take actions to attempt to
require the Government of Indonesia to honor its contractual
obligations; however, subsequent actions by the Government of
Indonesia and continued economic problems in Indonesia have
created further uncertainty as to whether the contracts for such
projects will be abrogated by the Indonesian government and
accordingly have created significant risks to the completion of
these projects. As a result, the Company recorded a SFAS 121
asset valuation impairment charge of $87,000 in the fourth
quarter of 1997. This charge includes all reasonably estimated
asset valuation impairments associated with the Company's assets
in Indonesia and gives effect to the political risk insurance on
such investments.
On December 2, 1994, a subsidiary of the Company, Himpurna
California Energy Ltd. ("HCE") executed a joint operation
contract (the "Dieng JOC") for the development of the geothermal
steam field and geothermal power facilities at the Dieng
geothermal field, located in Central Java (the "Dieng Project")
with Perusahaan Pertambangan Minyak Dan Gas Bumi Negara
("Pertamina"), the Indonesian national oil company, and executed
a "take-or-pay" energy sales contract (the "Dieng ESC") with both
Pertamina and P.T. PLN (Persero) ("PLN"), the Indonesian national
electric utility. HCE was formed pursuant to a joint development
agreement with P.T. Himpurna Enersindo Abadi ("P.T. HEA"), its
Indonesian partner, which is a subsidiary of Himpurna, whereby
the Company and P.T. HEA have agreed to work together on an
exclusive basis to develop the Dieng Project (the "Dieng Joint
Venture"). Subsequent to the January 1998 KDG acquisition, the
Dieng Joint Venture is structured with subsidiaries of the
Company holding an approximate 94% interest (including certain
assignments of dividend rights representing an economic interest
of 4%), and P.T. HEA holding a 6% interest in the Dieng Project.
Financial closing and first disbursement of construction loan
funds occurred on October 3, 1996. Construction of Dieng Unit I
is expected to be completed in March 1998.
Pursuant to the Dieng JOC and ESC, Pertamina has granted to HCE
the geothermal field and the wells and other facilities presently
located thereon and HCE may build, own and operate power
production units with an aggregate capacity of up to 400 MW. HCE
will accept the field operation responsibility for developing and
supplying the geothermal steam and fluids required to operate the
plant. The Dieng JOC is structured as a build own operate
transfer agreement and will expire (subject to extension by
mutual agreement) on the date which is the later of (i) 42 years
following effectiveness of the Dieng JOC and (ii) 30 years
following the date of commencement of commercial generation of
the final unit. Upon the expiration of the proposed Dieng JOC,
all facilities will be transferred to Pertamina at no cost.
HCE began well testing in the fourth quarter of 1995 and issued a
notice to proceed for the construction and supply of an initial
55 net MW unit ("Dieng Unit I") in the first quarter of 1996. PT
Kiewit/Holt Indonesia, a consortium including Kiewit Construction
Group, Inc., a subsidiary of PKS ("KCG"), is constructing Dieng
Unit I pursuant to a fixed price, date certain, turnkey
construction contract ("Construction Contract"). Affiliates of
KCG are providing the engineered supply with respect to Dieng
Unit I pursuant to a fixed price, date certain, turnkey supply
contract ("Supply Contract"). The Construction Contract and
Supply Contract are sometimes referred to herein as the "Dieng
EPC" and KCG and their affiliates party to the Construction
Contract and Supply Contract are sometimes referred to herein,
collectively, as the "Construction Consortium." The obligations
of the Construction Consortium under the Construction and Supply
Contracts are supported by a guaranty of KCG. KCG is the lead
member of the Construction Consortium, with a 60% interest. HCE
will be responsible for operating and managing the Dieng Project.
In the fourth quarter of 1997, HCE issued a notice to proceed and
closed the project financing for the construction and supply of
the Dieng Unit II 80 net MW project. The same construction
consortium as described above for Dieng Unit I has contracted to
construct Dieng Unit II under similar terms. The Company has
contributed the necessary equity for the completion of Dieng Unit
II and the construction loan of $109,000 was arranged under the
June 1997 CE Indonesia Funding Corp. facility. However, pending
resolution of the current uncertainties associated with
Indonesia, construction activities on this project have been
significantly reduced.
Patuha Power, Ltd. ("Patuha Power") is developing a geothermal
power plant in the Patuha geothermal field in Java, Indonesia
(the "Patuha Project"). On December 2, 1994, Patuha Power
executed both a joint operation contract and an energy sales
contract, each of which contains terms substantially similar to
those described above for the Dieng Project. Patuha Power began
well testing and exploration in the fourth quarter of 1995 and in
the third quarter of 1997, issued a notice to proceed for the
construction and supply of the Patuha Unit I 80 net MW project.
The same construction consortium as described above for Dieng
Unit I has contracted to construct Patuha Unit I under similar
terms. The Company has contributed the necessary equity for the
completion of Patuha Unit I and the construction loan of $150,000
was arranged under the June 1997 CE Indonesia Funding Corp.
facility. However, pending resolution of the current
uncertainties associated with Indonesia, construction activities
on this project have been significantly reduced.
The Company and PT Panutan Group, an Indonesian consortium of
energy, oil, gas and mining companies, have formed a joint
venture to pursue the development of geothermal resources in Bali
(the "Bali Project"). The PT Panutan Group is entitled to
contribute up to 40% of the total equity and obtain up to 40% of
the net profit of the Bali Project. The project company
developing the Bali Project, Bali Energy Ltd. ("Bali Energy"),
has executed both a joint operation contract and an energy sales
contract with terms similar to those at Dieng and Patuha.
However, pending resolution of the current uncertainties
associated with Indonesia, infrastructure construction and
drilling activities on this project have been significantly
reduced.
The Company developed and owns the rights to a proprietary
process for the extraction of minerals from elements in solution
in the geothermal brine and fluids utilized at its Imperial
Valley plants (the "Salton Sea Extraction Project") as well as
the production of power to be used in the extraction process.
The initial phase of the project would require delivery of 49 net
MW of power. A pilot plant has successfully produced commercial
quality zinc at the Company's Imperial Valley Project. Zinc is
primarily used in galvanizing steel for use in the automobile
industry. The Company intends to sequentially develop manganese,
silver, gold, lead, boron, lithium and other products as it
further develops the extraction technology. The Company is also
investigating producing silica from the solids precipitated out
of the geothermal power process. Silica is used as a filler for
such products as paint, plastics and high temperature cement. If
successfully developed, the mineral extraction process will
provide an environmentally responsible and low cost minerals
recovery methodology.
Subsidiaries of Magma, a subsidiary of the Company, sought new
long-term final SO4 power purchase agreements in the Salton Sea
area through the bidding process adopted by the California Public
Utilities Commission ("CPUC") under its 1992 Biennial Resource
Plan Update ("BRPU"). In its BRPU, the CPUC cited the need for an
additional 9,600 MW of power production through 1999 among
California's three investor-owned utilities, Southern California
Edison Company ("Edison"), San Diego Gas and Electric ("SDG&E")
and Pacific Gas and Electric Company. Of this amount, 275 MW was
set aside for bidding by independent power producers (such as
Magma) utilizing renewable resources. Pursuant to an order of the
CPUC dated June 22, 1994 (confirmed on December 21, 1994), Magma
was awarded 163 net MW for sale to Edison and SDG&E, with in-
service dates in 1997 and 1998. On February 23, 1995 the Federal
Energy Regulatory Commission ("FERC") issued an order finding
that the CPUC's BRPU program violated the Public Utilities
Regulatory Policies Act ("PURPA") and FERC's implementing
regulations and recommended negotiated settlements. In response,
the CPUC issued an Assigned Commissioners Ruling encouraging
settlements between the final winning bidders and the utilities.
The utilities are expected to continue to challenge the BRPU and,
in light of the regulatory uncertainty, there can be no assurance
that power sales contracts will be executed or that any such
projects will be completed. In light of these developments, the
Company agreed to execute an agreement with Edison on March 16,
1995, providing that in certain circumstances it would withdraw
its Edison BRPU bid in consideration for the payment of certain
sums. In December 1996, the Company entered into a confidential
cash buyout agreement with SDG&E. These agreements are subject
to CPUC approval.
Within the United Kingdom there was continued investment to
extend and improve the electricity distribution network.
Expenditures in the year were approximately $102,000 although
customers directly contributed approximately $33,000 to the
additional costs incurred in expanding the system to meet their
specific requirements.
The Company is actively seeking to develop, construct, own and
operate new energy projects, both domestically and
internationally, the completion of any of which is subject to
substantial risk. Development can require the Company to expend
significant sums for preliminary engineering, permitting, fuel
supply, resource exploration, legal and other expenses in
preparation for competitive bids which the Company may not win or
before it can be determined whether a project is feasible,
economically attractive or capable of being financed. Successful
development and construction is contingent upon, among other
things, negotiation on terms satisfactory to the Company of
engineering, construction, fuel supply and power sales contracts
with other project participants, receipt of required governmental
permits and consents and timely implementation of construction.
There can be no assurance that development efforts on any
particular project, or the Company's development efforts
generally, will be successful.
The Company believes that the international independent power
market holds the majority of new opportunities for financially
attractive private power generation development in the next
several years. The financing, construction and development of
projects outside the United States entail significant political
and financial risks (including, without limitation, uncertainties
associated with first time privatization efforts in the countries
involved, currency exchange rate fluctuations, currency
repatriation restrictions, political instability, civil unrest
and expropriation) and other structuring issues that have the
potential to cause substantial delays or material impairment of
value to the project being developed, which the Company may not
be fully capable of insuring against. The uncertainty of the
legal environment in certain foreign countries in which the
Company may develop or acquire projects could make it more
difficult for the Company to enforce its rights under agreements
relating to such projects. In addition, the laws and regulations
of certain countries may limit the ability of the Company to hold
a majority interest in some of the projects that it may develop
or acquire. The Company's international projects may, in certain
cases, be terminated by a government. 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 6, 1998, filed with the Securities and Exchange
Commission and incorporated herein by reference.
Inflation has not had a substantial impact on the Company's
operating revenues and costs; energy payments for electricity for
the Coso Project, Partnership Project, Salton Sea II Project and
Salton Sea III Project will continue to be based upon scheduled
rates and are not adjusted for inflation through the initial ten
year period after the dates of firm operation under each power
purchase agreement.
The Company has commenced, for all of its information systems, a
year 2000 date conversion project to address all necessary code
changes, testing and implementation. The "Year 2000 Computer
Problem" creates risk for the Company from unforeseen problems in
its own computer systems and from third parties with whom the
Company deals on financial transactions worldwide. Such failures
of the Company's and/or third parties' computer systems could
have a material impact on the Company's ability to conduct its
business, and especially to process and account for the transfer
of funds electronically. Management believes that the year 2000
implementation costs and related potential effect should not have
a material financial impact on the Company.
CONSOLIDATED BALANCE SHEETS
As of December 31, 1997 and 1996
Dollars and Shares in Thousands, Except Per Share Amounts
ASSETS 1997 1996
Cash and cash equivalents (Note 3) $ 1,445,338 $ 424,500
Joint venture cash and investments 6,072 47,764
Restricted cash 223,636 106,968
Short-term investments 1,282 4,921
Accounts receivable 376,745 342,307
Properties, plants, contracts and
equipment, net 3,528,910 3,225,496
Excess of cost over fair value of net
assets acquired, net 1,312,788 790,920
Equity investments 238,025 238,856
Deferred charges and other assets 354,830 448,424
Total assets $ 7,487,626 $ 5,630,156
LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable $ 173,610 $ 218,164
Other accrued liabilities 1,106,641 668,612
Parent company debt 1,303,845 1,146,685
Subsidiary and project debt 2,189,007 1,678,392
Deferred income taxes 509,059 469,199
Total liabilities 5,282,162 4,181,052
Deferred income 40,837 29,067
Commitments and contingencies (Notes 3, 18, 19 and 20)
Company - obligated mandatorily redeemable
convertible preferred securities
of subsidiary trusts 553,930 103,930
Preferred securities of subsidiary 56,181 136,065
Minority interest 134,454 299,252
Common stock and options subject to redemption 654,736 ---
Stockholders' equity:
Preferred stock - authorized 2,000 shares,
no par value --- ---
Common stock - par value $.0675 per share,
authorized 180,000 shares, issued 82,980
and 63,747 shares, outstanding 81,322 and
63,448 shares, respectively 5,602 4,303
Additional paid in capital 1,261,081 563,567
Retained earnings 213,493 297,520
Cumulative effect of foreign currency
translation adjustment (3,589) 29,658
Common stock and options subject to redemption (654,736) ---
Treasury stock - 1,658 and 299 common
shares at cost (56,525) (8,787)
Unearned compensation - restricted stock --- (5,471)
Total stockholders' equity 765,326 880,790
Total liabilities and stockholders' equity $ 7,487,626 $ 5,630,156
The accompanying notes are an integral part of these financial
statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Years Ended December 31, 1997
Dollars and Shares in Thousands, Except Per Share Amounts
1997 1996 1995
Revenue:
Operating revenue $2,166,338 $ 518,934 $ 335,630
Interest and other income 104,573 57,261 63,093
Total revenues 2,270,911 576,195 398,723
Costs and expenses:
Cost of sales 1,055,195 31,840 ---
Operating expense 345,833 132,655 103,602
General and administration 52,705 21,451 23,376
Depreciation and amortization 276,041 118,586 72,249
Loss on equity investment in Casecnan 5,972 5,221 362
Interest expense 296,364 165,900 134,637
Less interest capitalized (45,059) (39,862) (32,554)
Non-recurring charge - asset valuation
impairment 87,000 --- ---
Total costs and expenses 2,074,051 435,791 301,672
Income before provision for income taxes 196,860 140,404 97,051
Provision for income taxes 99,044 41,821 30,631
Income before minority interest 97,816 98,583 66,420
Minority interest 45,993 6,122 3,005
Income before extraordinary item 51,823 92,461 63,415
Extraordinary item, net of
minority interest of $58,222 (135,850) --- ---
Net income (loss) (84,027) 92,461 63,415
Preferred dividends --- --- 1,080
Net income (loss) available to
common stockholders $ (84,027) $ 92,461 $ 62,335
Income per share before extraordinary
item $ 0.77 $ 1.69 $ 1.32
Extraordinary item $ (2.02) $ --- $ ---
Net income (loss) per share $ (1.25) $ 1.69 $ 1.32
Income per share before extraordinary
item - diluted $ 0.75 $ 1.54 $ 1.22
Extraordinary item - diluted $ (1.97) $ --- $ ---
Net income (loss) per share - diluted $ (1.22) $ 1.54 $ 1.22
The accompanying notes are an integral part of these financial
statements.
<TABLE>
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Three Years Ended December 31, 1997
Dollars and Shares in Thousands
<CAPTION>
Common Stock
Outstanding Additional Foreign & Options
Common Common Paid-In Retained Currency Subject to Treasury Unearned
Shares Stock Capital Earnings Adjust. Redemption Stock Compensation Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Balance
December 31, 1994 31,849 $2,407 $100,421 $142,937 $ --- $ --- $(65,774) $ --- $179,991
Equity offering 18,170 1,004 240,825 --- --- --- 56,801 --- 298,630
Restricted stock 500 --- 848 --- --- --- 8,652 (9,500) ---
Exercise of stock options
and other equity
transactions 176 10 446 --- --- --- 563 2,494 3,513
Purchase of treasury
stock (102) --- --- --- --- --- (1,590) --- (1,590)
Preferred stock dividends, Series C,
including cash distribution
of $43 --- --- --- (1,293) --- --- --- --- (1,293)
Tax benefit from
stock plan --- --- 866 --- --- --- --- --- 866
Net income before
preferred dividends --- --- --- 63,415 --- --- --- --- 63,415
Balance December 31,
1995 50,593 3,421 343,406 205,059 --- --- (1,348) (7,006) 543,532
Exercise of stock options
and other equity
transactions 5,263 337 53,030 --- --- --- 4,569 1,535 59,471
Purchase of treasury
stock (472) --- --- --- --- --- (12,008) --- (12,008)
Conversion of debt 8,064 545 164,912 --- --- --- --- --- 165,457
Tax benefit from
stock plan --- --- 2,219 --- --- --- --- --- 2,219
Foreign currency translation
adjustment --- --- --- --- 29,658 --- --- --- 29,658
Net income --- --- --- 92,461 --- --- --- --- 92,461
Balance December 31,
1996 63,448 4,303 563,567 297,520 29,658 --- (8,787) (5,471) 880,790
Equity offering 19,100 1,289 697,315 --- --- --- --- --- 698,604
Exercise of stock options
and other equity
transactions 396 10 (2,757) --- --- --- 7,767 5,471 10,491
Purchase of treasury
stock (1,622) --- --- --- --- --- (55,505) --- (55,505)
Common stock and options
subject to
redemption --- --- --- --- --- (654,736) --- --- (654,736)
Tax benefit from
stock plan --- --- 2,956 --- --- --- --- --- 2,956
Foreign currency
translation
adjustment --- --- --- --- (33,247) --- --- --- (33,247)
Net loss --- --- --- (84,027) --- --- --- --- (84,027)
Balance December 31,
1997 81,322 $5,602 $1,261,081 $213,493$(3,589)$(654,736) $(56,525)$ ---$ 765,326
</TABLE>
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Years Ended December 31, 1997
Dollars in Thousands
1997 1996 1995
Cash flows from operating activities:
Net income (loss) $ (84,027) $ 92,461 $ 63,415
Adjustments to reconcile net cash flow from operating activities:
Non-recurring charge-asset valuation
impairment 87,000 --- ---
Depreciation and amortization 239,234 109,447 65,244
Amortization of excess of cost over
fair value of net assets acquired 36,807 9,139 7,005
Amortization of original issue discount 2,160 50,194 45,409
Amortization of deferred financing costs 26,161 9,677 8,979
Amortization of unearned compensation 5,471 1,535 2,494
Provision for deferred income taxes 55,584 12,252 13,983
Loss (income) on equity investments (16,068) (910) 362
Income (loss) applicable to minority
interest (35,387) 1,431 3,005
Changes in other items:
Accounts receivable (34,146) (13,936) 213
Accounts payable, accrued liabilities
and deferred income 29,799 2,093 12,103
Net cash flows from operating activities 312,588 273,383 222,212
Cash flows from investing activities:
Purchase of Northern, Falcon Seaboard, Partnership Interest
and Magma, net of cash acquired (632,014) (474,443) (907,614)
Distributions from equity investments 23,960 8,222 ---
Capital expenditures relating to operating
projects (194,224) (24,821) (27,120)
Philippine construction (27,334) (167,160) (289,655)
Indonesian and other development (155,963) (81,068) (8,973)
Salton Sea IV construction --- (63,772) (62,430)
Pacific Northwest, Nevada, and Utah
exploration costs (3,128) (4,885) (10,445)
Decrease in short-term investments 2,880 33,998 80,565
Decrease (increase) in restricted cash (116,668) 63,175 (17,452)
Other 60,390 (2,910) 11,514
Investment in Casecnan --- --- (61,177)
Net cash flows from investing activities (1,042,101) (713,664) (1,292,787)
Cash flows from financing activities:
Proceeds from sale of common and treasury stock
and exercise of stock options 703,624 54,935 299,649
Proceeds from convertible preferred securities
of subsidiary trusts 450,000 103,930 ---
Proceeds from issuance of parent company debt 350,000 324,136 200,000
Repayment of parent company debt (100,000) --- ---
Net proceeds from revolver (95,000) 95,000 ---
Proceeds from subsidiary and project debt 795,658 428,134 654,695
Repayments of subsidiary and project debt (271,618) (210,892) (176,664)
Deferred charges relating to debt financing (48,395) (36,010) (34,733)
Purchase of treasury stock (55,505) (12,008) (1,590)
Other 13,142 10,756 (29,169)
Net cash flows from financing activities 1,741,906 757,981 912,188
Effect of exchange rate changes (33,247) 4,860 ---
Net increase (decrease) in cash and
investments 979,146 322,560 (158,387)
Cash and cash equivalents at beginning
of year 472,264 149,704 308,091
Cash and cash equivalents at end of year $ 1,451,410 $ 472,264 $ 149,704
Supplemental Disclosures:
Interest paid (net of amounts capitalized)$ 316,060 $ 92,829 $ 50,840
Income taxes paid $ 44,483 $ 23,211 $ 14,812
The accompanying notes are an integral part of these
financial statements.
NOTES Consolidated Financial Statements
For the Three Years Ended December 31, 1997
Dollars, Pounds and Shares in Thousands, Except Per Share Amounts
1. Business
CalEnergy Company, Inc. (the "Company") is a United States-based
global power company which generates, distributes and supplies
electricity to utilities, government entities, retail customers and
other customers located throughout the world. The Company was founded
in 1971 and through its subsidiaries is primarily engaged in the
development, ownership and operation of environmentally responsible
independent power production facilities worldwide utilizing
geothermal, natural gas, hydroelectric and other energy sources. In
addition, the Company is engaged in the distribution and supply of
electricity to approximately 1.5 million customers primarily in
northeast England as well as the generation and supply of electricity
(together with other related business activities) throughout England
and Wales. The Company is also active in supplying gas and has
applications for over 400,000 customers in those areas of England,
Wales and Scotland where retail gas competition has been introduced.
The Company has organized several partnerships and joint ventures
(herein referred to as the "Coso Joint Ventures") in order to develop
geothermal energy at the China Lake Naval Air Weapons Station, Coso
Hot Springs, China Lake, California. Collectively, the projects
undertaken by these Coso Joint Ventures are referred to as the Coso
Project. In 1992, the Company entered into the natural gas-fired
electrical generation market through the purchase of a development
opportunity in Yuma, Arizona which commenced commercial operation in
May 1994. In 1993, the Company started developing a number of
international power project opportunities where private power
generating programs have been initiated, including the Philippines and
Indonesia. In 1995, the Company acquired Magma Power Company
("Magma"). Magma's operating assets included four projects referred to
as the Partnership Project in which Magma had a 50% interest, and
three projects referred to as the Salton Sea Project of which Magma
owned 100%. A fourth project included in the Salton Sea Project was
constructed after the acquisition of Magma and commenced operations in
June 1996. In addition, in April 1996, the Company acquired the
remaining 50% interest in the Partnership Project. In August 1996,
the Company acquired Falcon Seaboard Resources, Inc. ("Falcon
Seaboard") which includes significant interests in three operating gas-
fired cogeneration facilities and a related natural gas pipeline. On
December 24, 1996, CE Electric UK plc ("CE Electric"), which in 1997
was 70% owned indirectly by the Company and 30% owned indirectly by
Peter Kiewit Sons', Inc. ("PKS"), acquired majority ownership of the
outstanding ordinary share capital of Northern Electric plc
("Northern") pursuant to a tender offer ("Tender Offer"). As of March
18, 1997, CE Electric effectively owned 100% of Northern ordinary
shares.
Northern is one of the twelve regional electricity companies ("RECs")
which came into existence as a result of the restructuring and
subsequent privatization of the electricity industry in the United
Kingdom in 1990. Northern is primarily engaged in the distribution
and supply of electricity. Northern was granted a Public Electricity
Supply ("PES") license under the Electricity Act to supply electricity
in Northern's Authorized Area ("Authorized Area"). Northern's
Authorized Area covers approximately 14,400 square kilometers with a
population of approximately 3.2 million people and includes the
counties of Northumberland, Tyne and Wear, Durham, Cleveland and North
Yorkshire. Northern supplies electricity outside its Authorized Area
pursuant to second tier licenses. Northern also is involved in non-
regulated activities, including the supply of gas within England,
Wales and Scotland, the generation of electricity, electrical
appliance retailing and gas exploration and production.
2. Summary of Significant Accounting Policies
The consolidated financial statements include the accounts of the
Company, its wholly-owned subsidiaries, and its proportionate share of
the partnerships and joint ventures in which it has an undivided
interest in the assets and is proportionally liable for its share of
liabilities. Other investments and corporate joint ventures where the
Company has the ability to exercise significant influence are
accounted for under the equity method of accounting. Investments,
where the Company's ability to influence is limited, are accounted for
under the cost method of accounting. All significant inter-enterprise
transactions and accounts have been eliminated. The results of
operations of the Company include the Company's proportionate share of
results of operations of entities acquired as of the date of each
acquisition.
Cash Equivalents, Investments and Restricted Cash
The Company considers all investment instruments purchased with an
original maturity of three months or less to be cash equivalents.
Restricted cash is not considered a cash equivalent.
Investments other than restricted cash are primarily commercial paper
and money market securities. The restricted cash balance includes such
securities and mortgage backed securities, and is mainly composed of
amounts deposited in restricted accounts from which the Company will
source its equity contributions and debt service reserve requirements
relating to the projects. These funds are restricted by their
respective project debt agreements to be used only for the related
project.
At December 31, 1997, all of the Company's investments are classified
as held-to-maturity and are accounted for at their amortized cost
basis. The carrying amount of the investments approximates the fair
value based on quoted market prices as provided by the financial
institution which holds the investments.
Properties, Plants, Contracts, Equipment and Depreciation
The cost of major additions and betterments are capitalized, while
replacements, maintenance, and repairs that do not improve or extend
the lives of the respective assets are expensed.
Depreciation of the operating power plant costs, net of salvage value,
is computed on the straight line method over the estimated useful
lives, between 10 and 30 years. Depreciation of furniture, fixtures
and equipment which are recorded at cost, is computed on the straight
line method over the estimated useful lives of the related assets,
which range from three to ten years.
The Northern, Falcon Seaboard, Partnership Interest and Magma
acquisitions by the Company have been accounted for as purchase
business combinations. All identifiable assets acquired and
liabilities assumed were assigned a portion of the cost of acquiring
the respective companies equal to their fair values at the date of the
acquisition and include the following:
Property and equipment of Northern is depreciated using a
systematic method, which approximates the straight line
method over the estimated useful lives of the related assets
which range from 3-40 years.
Power sales agreements are amortized separately over (1) the
remaining portion of the scheduled price periods of the
power sales agreements and (2) for the Partnership Interest
and Magma acquisitions the 20 year avoided cost periods of
the power sales agreements using the straight line method.
Capitalized costs for gas reserves, other than costs of unevaluated
exploration projects and projects awaiting development consent, are
depleted using the unit of production method. Depletion is calculated
based on hydrocarbon reserves of properties in the evaluated pool
estimated to be commercially recoverable and include anticipated
future development costs in respect of those reserves.
Expenditures on major information technology systems are capitalized
and depreciated on a straight line basis over the useful life of the
developed systems which range from 3-10 years.
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 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
Total acquisition costs in excess of the fair values assigned to the
net assets acquired are amortized over a 40 year period for the
Northern and Magma acquisitions and a 25 year period for the Falcon
Seaboard acquisition, both using the straight line method.
Impairment of Long-Lived Assets
The Company reviews long-lived assets and certain identifiable
intangibles for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be recoverable.
An impairment loss would be recognized whenever evidence exists that
the carrying value is not recoverable.
Deferred Well and Rework Costs
Well rework costs are deferred and amortized over the estimated period
between reworks. These deferred costs, net of accumulated
amortization, are $5,421 and $8,371 at December 31, 1997 and 1996,
respectively, and are included in other assets.
Revenue Recognition
Revenues are recorded based upon service rendered and electricity and
steam delivered, distributed or supplied to the end of the month.
Where there is an overrecovery of supply or distribution business
revenues against the maximum regulated amount, revenues are deferred
equivalent to the overrecovered amount. The deferred amount is
deducted from revenue and included in other liabilities. Where there
is an underrecovery, no anticipation of any potential future recovery
is made.
Capitalization of Interest and Deferred Financing Costs
Prior to the commencement of operations, interest is capitalized on
the costs of the plants and geothermal resource development to the
extent incurred. Capitalized interest and other deferred charges are
amortized over the lives of the related assets.
Deferred financing costs are amortized over the term of the related
financing using the effective interest method.
Deferred Income Taxes
The Company recognizes deferred tax assets and liabilities based on
the difference between the financial statement and tax bases of assets
and liabilities using estimated tax rates in effect for the year in
which the differences are expected to reverse. The Company intends to
repatriate earnings of foreign subsidiaries in the foreseeable future.
As a result, deferred income taxes are provided for retained earnings
of international subsidiaries and corporate joint ventures which are
intended to be remitted.
Fair Values of Financial Instruments
The following methods and assumptions were used by the Company in
estimating fair values of financial instruments as discussed herein.
Fair values have been estimated based on quoted market prices for debt
issues listed on exchanges. Fair values of financial instruments that
are not actively traded are based on market prices of similar
instruments and/or valuation techniques using market assumptions.
The Company assumes that the carrying amount of short-term financial
instruments approximates their fair value. For these purposes, short-
term is defined as any item that matures, reprices, or represents a
cash transaction between willing parties within six months or less of
the measurement date.
Pensions
Northern contributes to the Electricity Supply Pension Scheme and
contributions to the scheme are charged to the income statement. The
capital cost of ex gratia and supplementary pensions are normally
charged to the income statement in the period in which they are
granted. Variations in pension cost, which are identified as a result
of actuarial valuations/reviews, are amortized over the average
expected remaining working lives of employees in proportion to their
expected payroll costs. Differences between the amounts funded and
the amounts charged to the profit and loss account are treated as
either provisions or prepayments in the balance sheet.
Net Income per Common Share
In February 1997, the Financial Accounting Standards Board ("FASB")
adopted Statement of Financial Accounting Standards ("SFAS") No. 128,
"Earnings per Share." SFAS 128 replaced primary and fully diluted
earnings per share with basic and diluted earnings per share,
respectively.
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
to diluted earnings per share before extraordinary item follows:
1997 1996 1995
Per-Share Per-Share Per-Share
Income Shares Amount Income Shares Amount Income Shares Amount
Basic earnings
per share before
extraordinary
item $ 51,823 67,268 $0.77 $ 92,461 54,739 $1.69 $62,335 47,249 $1.32
Effect of dilutive securities
Stock options --- 1,418 --- 1,881 --- 1,688
Convertible preferred securities
of subsidiary
trusts(1) --- --- 2,840 2,517 --- ---
Convertible debt --- --- 4,968 5,935 6,038 7,258
Diluted earnings per share
before extraordinary
item $ 51,823 68,686 $0.75 $100,269 65,072 $1.54 $68,373 56,195 $1.22
(1) The convertible preferred securities of subsidiary trusts were
antidilutive in 1997.
Reclassification
Certain amounts in the fiscal 1996 and 1995 financial statements and
supporting footnote disclosures have been reclassified to conform to
the fiscal 1997 presentation. Such reclassification did not impact
previously reported net income or retained earnings.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ
from those estimates.
New Accounting Pronouncements
In June 1997, the FASB adopted SFAS No. 130, "Reporting Comprehensive
Income", and No. 131, "Disclosures about Segments of an Enterprise and
Related Information". SFAS 130 establishes standards for reporting
and display of comprehensive income and its components in a full set
of general purpose financial statements. SFAS 131 redefines how
operating segments are determined and requires disclosure of certain
financial and descriptive information about a company's operating
segments. Both statements will be effective for the Company beginning
January 1, 1998. The Company has not yet determined the impact of
these statements on current disclosures.
3. KDG Acquisition
On September 11, 1997, the Company signed a definitive agreement with
Kiewit Diversified Group ("KDG"), a wholly owned subsidiary of PKS,
for the Company to purchase KDG's ownership interest in various
project partnerships and CalEnergy common shares (the "KDG
Acquisition"). Accordingly, common stock and options subject to
redemption have been reclassified in the consolidated balance sheet.
KDG's ownership interest in CalEnergy comprised approximately 20,231
shares of common stock (assuming exercise by KDG of one million
options to purchase CalEnergy shares), the 30% interest in Northern
Electric, as well as the following minority project interests:
Mahanagdong (45%), Casecnan (35%), Dieng (47%), Patuha (44%) and Bali
(30%) and other interests in international development stage projects.
CalEnergy paid $1,159,215 for the KDG Acquisition and final closing of
the transaction occurred in January 1998. CalEnergy funded this
acquisition with available cash and the net proceeds of the equity
offering and the debt offering completed in October 1997.
4. Acquisitions
Northern
On December 24, 1996, CE Electric UK plc ("CE Electric"), which in
1997 was 70% owned indirectly by the Company and 30% owned indirectly
by PKS, acquired majority ownership of the outstanding ordinary share
capital of Northern Electric plc ("Northern") pursuant to a tender
offer (the "Northern Tender Offer") commenced in the United Kingdom on
November 5, 1996. As of March 18, 1997, CE Electric effectively
acquired the remaining ordinary shares and owned 100% of Northern's
ordinary shares.
The Company and PKS contributed to CE Electric approximately $410,000
and $176,000 respectively, of the approximately $1,200,000 required to
acquire all of Northern's ordinary and preference shares in connection
with the Tender Offer. The Company obtained such funds from cash on
hand, short-term borrowings, and borrowings of approximately $100,000
under a Credit Agreement entered into with Credit Suisse on October
28, 1996 (the "CalEnergy Credit Facility"). The Company has repaid
the entire CalEnergy Credit Facility through the use of proceeds of
the Trust Securities offering. The remaining funds necessary to
consummate the Tender Offer were provided from a pound 560,000 Term Loan
and Revolving Facility Agreement, dated October 28, 1996 (the "U.K.
Credit Facility"). CE Electric has repaid the entire U.K. Credit
Facility through the use of proceeds of the senior note and sterling
bond offerings of CE Electric UK Funding Company.
The Northern acquisition has been accounted for as a purchase business
combination. All identifiable assets acquired and liabilities assumed
were assigned a portion of the cost of acquiring Northern, equal to
their fair values at the date of the acquisition. Minority interest
was recorded at historical cost.
In 1993, Northern entered into a contract relating to the purchase of
400 MW of capacity from a 15.4% owned related party, Teesside Power
Limited ("Teesside"), for a period of 15 years beginning April 1,
1993. The contract sets escalating purchase prices at predetermined
levels. Currently the escalating contract prices exceed those paid by
the Company to the electricity pool (the "Pool") which is operated by
the National Grid Group. However, under current price cap regulation
expected to expire in 1998 the Company is able to recover these costs.
For the period after the price cap regulation ends, the Company has
established a liability for the estimated loss as a result of this
contract.
Northern utilizes contracts for differences ("CFDs") to mitigate its
exposure to volatility in the prices of electricity purchased through
the Pool. Such contracts allow the Company to effectively convert the
majority of its anticipated Pool purchases from market to fixed
prices. As of December 31, 1997, CFDs were in place to hedge a
portion of electricity purchases of approximately 55,000 GWh through
the year 2008.
Falcon Seaboard
On August 7, 1996 the Company completed the acquisition of Falcon
Seaboard for a cash price of $229,500 including acquisition costs.
Through the acquisition, the Company indirectly acquired significant
ownership interests in three operating gas-fired cogeneration
facilities and a related natural-gas pipeline. The plants are
located in Texas, Pennsylvania and New York and total 520 MW in
capacity.
The Falcon Seaboard acquisition has been accounted for as a purchase
business combination. All identifiable assets acquired and
liabilities assumed were assigned a portion of the cost of acquiring
Falcon Seaboard, equal to their fair values at the date of the
acquisition.
Edison Mission Energy's Partnership Interest
On April 17, 1996 the Company completed the acquisition of Edison
Mission Energy's Partnership Interests in four geothermal operating
facilities in California for a cash purchase price of $71,000
including acquisition costs. The four projects, Vulcan, Hoch (Del
Ranch), Leathers and Elmore, are located in the Imperial Valley of
California. Prior to this transaction, the Company was a 50% owner of
these facilities.
The Partnership Interest acquisition has been accounted for as a
purchase business combination. All identifiable assets acquired and
liabilities assumed were assigned a portion of the cost of acquiring
the Partnership Interest, equal to their fair values at the date of
the acquisition.
Unaudited pro forma combined revenue, income and basic earnings per
share before extraordinary item of the Company, Northern, Falcon
Seaboard, and the Partnership Interest for the twelve months ended
December 31, 1997 and 1996, as if the acquisitions had occurred at the
beginning of 1996 after giving effect to certain pro forma adjustments
related to the acquisitions were $2,270,911, $52,430, and $0.78
compared to $2,162,381, $64,811 and $1.18, respectively. Excluding
the $87,000, $1.29 per share, non-recurring charge, pro forma income
before extraordinary item would have been $139,430 in 1997.
5.Properties, Plants, Contracts and Equipment
Properties, plants, contracts and equipment comprise the following at
December 31:
1997 1996
Operating project costs:
Distribution system $1,237,743 $928,575
Power plants 1,464,885 1,277,663
Wells and resource development 395,314 377,731
Power sales agreements 227,535 227,535
Other assets 254,973 176,483
Total operating assets 3,580,450 2,987,987
Less accumulated depreciation and
amortization (497,832) (271,216)
Net operating assets 3,082,618 2,716,771
Mineral and gas reserves, net 297,048 270,851
Construction in progress:
Malitbog --- 152,411
Indonesia 140,172 81,875
Other development 9,072 3,588
Total $ 3,528,910 $ 3,225,496
Coso Project Operating Facilities
The Coso Project operating facilities comprise the Company's
proportionate share of the assets of three of its Coso Joint Ventures:
Coso Finance Partners ("Navy I Joint Venture"), Coso Energy Developers
("BLM Joint Venture"), and Coso Power Developers ("Navy II Joint
Venture"). The Navy I power plant is located on land owned by and
leased from the U.S. Navy to December 2009, with a 10 year extension
at the option of the Navy. Under terms of the Navy I Joint Venture,
current profits and losses are allocated 46.4% to the Company. The
BLM power plant is situated on lands leased from the U.S. Bureau of
Land Management under a geothermal lease agreement that extends until
October 31, 2035. The lease may be extended to 2075 at the option of
the BLM. Under the terms of the BLM Joint Venture agreement, the
Company's share of profits and losses is 48%. Under terms of the Navy
II Joint Venture, all profits, losses and capital contributions for
Navy II are divided equally by the two partners.
The amount of royalties paid by Navy I to the U.S. Navy to develop
geothermal energy for Navy I, Unit 1 on the lands owned by the Navy
comprises (i) a fee payable during the term of the contract based on
the difference between the amounts paid by the Navy to Edison for
specified quantities of electricity and the price as determined under
the contract (which currently approximates 73% of that paid by the
Navy to Edison), and (ii) $25,000 payable in December 2009, of which
the Company's share is $11,600. The $25,000 payment is secured by
funds placed on deposit monthly, which funds, plus accrued interest,
will aggregate $25,000. The monthly deposit is currently $50. As of
December 31, 1997, the balance of funds deposited approximated $6,337,
which amount is included in restricted cash.
Units 2 and 3 of Navy I and the Navy II power plants are on Navy
lands, for which the Navy receives a royalty based on electric sales
revenue at the initial rate of 4% escalating to 22% by the end of the
contract in December 2019. The BLM is paid a royalty of 10% of the
value of steam produced by the geothermal resource supplying the BLM
Plant.
The Coso Joint Ventures had royalty expense included in operating
expenses of $13,458, $13,412 and $13,623 in the years ended December
31, 1997, 1996 and 1995, respectively.
Imperial Valley Project Operating Facilities
The Company currently operates eight geothermal power plants in the
Imperial Valley in California. The Partnership Project consists of the
Vulcan, Hoch (Del Ranch), Elmore, and Leathers Partnerships. The
remaining four plants which comprise the Salton Sea Project are
indirect wholly owned subsidiaries of the Company. These geothermal
power plants consist of Salton Sea I, Salton Sea II, Salton Sea III
and Salton Sea IV. The Partnership Project and the Salton Sea Project
are collectively referred to as the Imperial Valley Project. The
Imperial Valley Project commencement dates and nominal capacities are
as follows:
Imperial Valley Commencement Nominal
Plants Date Capacity
Vulcan February 10, 1986 34 MW
Hoch (Del Ranch) January 2, 1989 38 MW
Elmore January 1, 1989 38 MW
Leathers January 1, 1990 38 MW
Salton Sea I July 1, 1987 10 MW
Salton Sea II April 5, 1990 20 MW
Salton Sea III February 13, 1989 49.8 MW
Salton Sea IV May 24, 1996 39.6 MW
The Partnership Project pays royalties based on both energy revenues
and total electricity revenues. Hoch (Del Ranch) and Leathers pay
royalties of approximately 5% of energy revenues and 1% of total
electricity revenue. Elmore pays royalties of approximately 5% of
energy revenues. Vulcan pays royalties of 4.167% of energy revenues.
The Salton Sea Project's weighted average royalty expense in 1997 was
approximately 6.1%. The royalties are paid to numerous recipients
based on varying percentages of electrical revenue or steam production
multiplied by published indices.
The Imperial Valley Projects had royalty expense included in operating
expenses of $14,343, $10,228 and $10,398 in the years ended December
31, 1997, 1996 and 1995, respectively.
Significant Customers and Contracts
All of the Company's sales of electricity from the Coso Project and
Imperial Valley Project, which comprise approximately 20% of 1997
operating revenue, are to Southern California Edison Company
("Edison") and are under long-term power purchase contracts.
The Coso Project and the Partnership Project sell all electricity
generated by the respective plants pursuant to seven long-term SO4
Agreements between the projects and Edison. These SO4 Agreements
provide for capacity payments, capacity bonus payments and energy
payments. Edison makes fixed annual capacity and capacity bonus
payments to the projects to the extent that capacity factors exceed
certain benchmarks. The price for capacity and capacity bonus payments
is fixed for the life of the SO4 Agreements. Energy is sold at
increasing scheduled rates for the first ten years after firm
operation and thereafter at Edison's Avoided Cost of Energy.
The scheduled energy price periods of the Coso Project SO4 Agreements
extended until at least August 1997 for each of the units operated by
the Navy I Partnership and extend until at least March 1999 and
January 2000 for each of the units operated by the BLM and Navy II
Partnerships, respectively. The Company's share of aggregate annual
capacity payments is approximately $17,000 and its share of aggregate
bonus payments is approximately $3,000.
The scheduled energy price periods of the Partnership Project SO4
Agreements extended until February 1996 for the Vulcan Partnership and
extend until December 1998, December 1998, and December 1999 for each
of the Hoch (Del Ranch), Elmore and Leathers Partnerships,
respectively. The annual capacity payments are approximately $24,500
and the bonus payments are approximately $4,400 in aggregate for the
four plants.
Excluding Navy I and Vulcan, which are receiving Edison's Avoided Cost
of Energy, the Company's SO4 Agreements provide for energy rates
ranging from 12.8 cents per kWh in 1997 to 15.6 cents per kWh in 1999. The
weighted average energy rate for all of the Company's SO4 Agreements
was 12.0 cents per kWh in 1997.
Salton Sea I sells electricity to Edison pursuant to a 30-year
negotiated power purchase agreement, as amended (the "Salton Sea I
PPA"), which provides for capacity and energy payments. The energy
payment is calculated using a Base Price which is subject to quarterly
adjustments based on a basket of indices. The time period weighted
average energy payment for Salton Sea I was 5.3 cents per kWh during 1997.
As the Salton Sea I PPA is not an SO4 Agreement, the energy payments
do not revert to Edison's Avoided Cost of Energy. The capacity
payment is approximately $1,100 per annum.
Salton Sea II and Salton Sea III sell electricity to Edison pursuant
to 30-year modified SO4 Agreements that provide for capacity payments,
capacity bonus payments and energy payments. The price for contract
capacity and contract capacity bonus payments is fixed for the life of
the modified SO4 Agreements. The energy payments for the first ten
year period, which period expires in April 2000 and February 1999 are
levelized at a time period weighted average of 10.6 cents per kWh and 9.8
cents per kWh for Salton Sea II and Salton Sea III, respectively.
Thereafter, the monthly energy payments will be Edison's Avoided Cost
of Energy. For Salton Sea II only, Edison is entitled to receive, at
no cost, 5% of all energy delivered in excess of 80% of contract
capacity through September 30, 2004. The annual capacity and bonus
payments for Salton Sea II and Salton Sea III are approximately $3,300
and $9,700, respectively.
The Salton Sea IV Project sells electricity to Edison pursuant to a
modified SO4 agreement which provides for contract capacity payments
on 34 MW of capacity at two different rates based on the respective
contract capacities deemed attributable to the original Salton Sea PPA
option (20 MW) and to the original Fish Lake PPA (14 MW). The capacity
payment price for the 20 MW portion adjusts quarterly based upon
specified indices and the capacity payment price for the 14 MW portion
is a fixed levelized rate. The energy payment (for deliveries up to a
rate of 39.6 MW) is at a fixed price for 55.6% of the total energy
delivered by Salton Sea IV and is based on an energy payment schedule
for 44.4% of the total energy delivered by Salton Sea IV. The
contract has a 30-year term but Edison is not required to purchase the
20 MW of capacity and energy originally attributable to the Salton Sea
I PPA option after September 30, 2017, the original termination date
of the Salton Sea I PPA.
For the year ended December 31, 1997, and 1996 Edison's average
Avoided Cost of Energy was 3.3 cents and 2.5 cents, respectively, per kWh which
is substantially below the contract energy prices earned for the year
ended December 31, 1997. Estimates of Edison's future Avoided Cost of
Energy vary substantially from year to year. The Company cannot
predict the likely level of Avoided Cost of Energy prices under the
SO4 Agreements and the modified SO4 Agreements at the expiration of
the scheduled payment periods. The revenues generated by each of the
projects operating under SO4 Agreements could decline significantly
after the expiration of the respective scheduled payment periods.
Philippine Projects
The Upper Mahiao Project was deemed complete in June 1996 and began
receiving capacity payments pursuant to the Upper Mahiao Energy
Conversion Agreement ("ECA"), in July of 1996. The project is
structured as a ten year build-own-operate-transfer project ("BOOT"),
in which the Company's subsidiary CE Cebu Geothermal Power Company,
Inc. ("CE Cebu"), the project company, is responsible for providing
operations and maintenance during the ten year BOOT period. The
electricity generated by the Upper Mahiao geothermal power plant is
sold to PNOC-Energy Development Corporation ("PNOC-EDC"), which is
also responsible for supplying the facility with the geothermal steam.
After the ten year cooperation period, and the recovery by the Company
of its capital investment plus incremental return, the plant will be
transferred to PNOC-EDC at no cost.
PNOC-EDC is obligated to pay for electric capacity that is nominated
each year by CE Cebu, irrespective of whether PNOC-EDC is willing or
able to accept delivery of such capacity. PNOC-EDC pays to CE Cebu a
fee (the "Capacity Fee") based on the plant capacity nominated to PNOC-
EDC in any year (which, at the plant's design capacity, is
approximately 95% of total contract revenues) and a fee (the "Energy
Fee") based on the electricity actually delivered to PNOC-EDC
(approximately 5% of total contract revenues). Payments under the
Upper Mahiao ECA are denominated in U.S. Dollars, or computed in U.S.
dollars and paid in Philippine pesos at the then-current exchange
rate, except for the Energy Fee. Significant portions of the Capacity
Fee and Energy Fee are indexed to U.S. and Philippine inflation rates,
respectively. PNOC-EDC's payment requirements, and its other
obligations under the Upper Mahiao ECA are supported by the Government
of the Philippines through a performance undertaking.
Unit I of the Malitbog Project (the "Malitbog Project") was deemed
complete in July 1996 and Units II and III in July 1997 at which times
such units commenced receiving capacity payments under the Malitbog
ECA. The Malitbog Project is owned and operated by Visayas Geothermal
Power Company ("VGPC"), a Philippine general partnership that is
wholly owned, indirectly, by the Company. Under its contract, VGPC is
to sell 100% of its output on substantially the same basis as
described above for the Upper Mahiao Project to PNOC-EDC, which will
in turn sell the power to the National Power Corporation of the
Philippines ("NPC"). However, VGPC receives 100% of its revenues from
such sales in the form of capacity payments. As with the Upper Mahiao
Project, the Malitbog Project is structured as a ten year BOOT, in
which the Company is responsible for providing operations and
maintenance for the ten year BOOT period. After a ten year
cooperation period, and the recovery by the Company of its capital
investment plus incremental return, the plant will be transferred to
PNOC-EDC at no cost.
The Mahanagdong Project (the "Mahanagdong Project") was deemed
complete in July 1997 and accordingly, the Mahanagdong Project began
receiving capacity payments pursuant to the Mahanagdong ECA in August
of 1997. The Mahanagdong Project is owned and operated by CE Luzon
Geothermal Power Company, Inc., a Philippine corporation, that is
expected to be indirectly owned by the Company (after the KDG
Acquisition) subject to a minority partner participation. The
electricity generated by the Mahanagdong Project will be sold to PNOC-
EDC on a "take or pay" basis, which is also responsible for supplying
the facility with the geothermal steam. The terms of the Mahanagdong
ECA are substantially similar to those of the Upper Mahiao ECA. All
of PNOC-EDC's obligations under the Mahanagdong ECA are supported by
the Government of the Philippines through a performance undertaking.
The capacity fees are expected to be approximately 97% of total
revenues at the design capacity levels and the energy fees are
expected to be approximately 3% of such total revenues.
Gas Projects
The Saranac Project sells electricity to New York State Electric & Gas
pursuant to a 15 year negotiated power purchase agreement (the
"Saranac PPA"), which provides for capacity and energy payments.
Capacity payments, which in 1997 total 2.2 cents per kWh, are received for
electricity produced during "peak hours" as defined in the Saranac PPA
and escalate at approximately 4.1% annually for the remaining term of
the contract. Energy payments, which average 6.6 cents per kWh in 1997,
escalate at approximately 4.4% annually for the remaining term of the
Saranac PPA. The Saranac PPA expires in June of 2009.
The Power Resources Project sells electricity to Texas Utilities
Electric Company ("TUEC") pursuant to a 15 year negotiated power
purchase agreement (the "Power Resources PPA"), which provides for
capacity and energy payments. Capacity payments and energy payments,
which in 1997 are $3,032 per month and 2.96 cents per kWh, respectively,
escalate at 3.5% annually for the remaining term of the Power
Resources PPA. The Power Resources PPA expires in September 2003.
The NorCon Project sells electricity to Niagara Mohawk Power
Corporation ("Niagara") pursuant to a 25 year negotiated power
purchase agreement (the "NorCon PPA") which provides for energy
payments calculated pursuant to an adjusting formula based on
Niagara's ongoing Tariff Avoided Cost and the contractual Long-Run
Avoided Cost. The NorCon PPA term extends through December 2017. The
Company and Niagara are currently engaged in discussions regarding a
potential restructuring or buyout and termination of the NorCon PPA.
The Yuma Project sells electricity to SDG&E under an existing 30-year
power purchase contract. The energy is sold at SDG&E's Avoided Cost
of Energy and the capacity is sold to SDG&E at a fixed price for the
life of the power purchase contract. The contract term extends
through May 2024.
Nevada and Utah Properties
Roosevelt Hot Springs. The Company operates and owns an approximately
70% interest in a geothermal steam field which supplies geothermal
steam to a 23 net MW power plant owned by Utah Power & Light Company
("UP&L") located on the Roosevelt Hot Springs property under a 30-year
steam sales contract.
The Company obtained approximately $20,317 cash under a pre-sale
agreement with UP&L whereby UP&L paid in advance for the steam
produced by the steam field. The Company must make certain penalty
payments to UP&L if the steam produced does not meet certain quantity
and quality requirements.
Desert Peak. The Company is the owner and operator of a geothermal
plant at Desert Peak, Nevada that is currently selling electricity to
Sierra Pacific Power Company ("Sierra") at Sierra's Avoided Cost.
Subsequent to year end, an indirect subsidiary of the Company entered
into a lease agreement whereby they will lease the facility to another
power producer and receive rental payments.
Salton Sea Minerals Extraction
The Company developed and owns the rights to a proprietary process for
the extraction of minerals from elements in solution in the geothermal
brine and fluids utilized at its Imperial Valley plants (the "Salton
Sea Extraction Project") as well as the production of power to be used
in the extraction process. A pilot plant has successfully produced
commercial quality zinc at the Company's Imperial Valley Project. The
Company is also investigating producing silica from the solids
precipitated out of the geothermal power process.
Telephone Flat
Under a Bonneville Power Administration ("BPA") geothermal pilot
program, the Company has been developing a 30 net MW geothermal
project which was originally located in the Newberry Known Geothermal
Resource Area in Deschutes County, Oregon (the "Telephone Flat
Project"). Pursuant to an amended power sales contract the project
has been relocated to Telephone Flat and BPA has agreed to purchase 30
MW from the project with an option to purchase up to an additional 100
MW. The movement of the project to this alternative location and
BPA's purchase obligation are subject to obtaining a final
environmental impact statement relating to the new site location.
Completion of this project is subject to a number of significant
uncertainties and cannot be assured.
6. Equity Investments
At December 31, 1997, the Company had an indirect ownership of
approximately 35% in the Casecnan Project, a combined irrigation and
150 net MW hydroelectric power generation project located on the
island of Luzon in the Philippines. The Company is expected to
indirectly own approximately 70% of the Casecnan Project after the KDG
Acquisition.
The Company had an indirect ownership of 50% in the Mahanagdong
Project, subject to a minority partner participation. The Company will
indirectly own 100% of the Mahanagdong Project after the KDG
Acquisition.
The Company has an approximate 45% economic interest in Saranac Power
Partners, L.P. and a 20% economic interest in NorCon Power Partners,
L.P. as part of the Falcon Seaboard acquisition.
Summary financial information for these equity investments follows:
Casecnan Saranac NorCon Mahanagdong
As of and for the year ended
December 31, 1997:
Assets $ 482,527 $ 315,671 $ 118,415 $ 294,250
Liabilities 384,369 211,299 115,487 197,575
Net income (loss) (11,267) 43,097 4,072 14,996
As of and for the year ended December 31, 1996:
Assets 492,166 325,174 125,956 240,222
Liabilities 380,737 213,326 121,223 168,512
Net income (loss) (11,207) 40,005 (53) N/A
7. Parent Company Debt
Parent company debt comprises the following at December 31:
1997 1996
Senior discount notes $ 529,640 $ 527,535
9.5% senior notes 224,205 224,150
7.63% senior notes 350,000 ---
Limited recourse senior secured notes* 200,000 200,000
CalEnergy credit facility --- 100,000
Revolving credit facility --- 95,000
$ 1,303,845 $ 1,146,685
* The amount of recourse obligation to the parent was $0 at December
31, 1997.
Senior Discount Notes
In March 1994, the Company issued $400,000 of 10 1/4% Senior Discount
Notes which accrete to an aggregate principal amount of $529,640 at
maturity in 2004. The original issue discount 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 is payable semiannually on January 15 and July
15 of each year, commencing July 15, 1997. The Senior Discount Notes
are redeemable at any time on or after January 15, 1999 initially at a
redemption price of 105.125% declining to 100% on January 15, 2002
plus accrued interest to the date of redemption. The Senior Discount
Notes are unsecured senior obligations of the Company.
The Senior Discount Notes prohibit payment of cash dividends unless
certain financial ratios are met and unless the dividends do not
exceed 50% of the Company's accumulated adjusted consolidated net
income as defined, subsequent to April 1, 1994, plus the proceeds of
any stock issuance.
9.5% Senior Notes
On September 20, 1996, the Company issued $225,000 of 9.5% Senior
Notes (the "9.5% Senior Notes") due 2006. Interest on the 9.5% Senior
Notes is payable semiannually on March 15 and September 15 of each
year, commencing March 15, 1997. The 9.5% Senior Notes are redeemable
at any time on or after September 15, 2001 initially at a redemption
price of 104.75% declining to 100% on September 15, 2004 plus accrued
interest to the date of redemption. The 9.5% Senior Notes are
unsecured senior obligations of the Company.
7.63% Senior Notes
On October 28, 1997, the Company issued $350,000 of 7.63% Senior Notes
(the "7.63% Senior Notes") due 2007. Interest on the 7.63% Senior
Notes will be payable semiannually on April 15 and October 15 of each
year, commencing April 15, 1998. The 7.63% Senior Notes are unsecured
senior obligations of the Company.
Limited Recourse Senior Secured Notes
On July 21, 1995, the Company issued $200,000 of 9 7/8% Limited
Recourse Senior Secured Notes Due 2003 (the "Notes"). Interest on the
Notes is payable on June 30 and December 30 of each year, commencing
December 1995. The Notes are secured by an assignment and pledge of
100% of the outstanding capital stock of Magma and are recourse only
to such Magma capital stock, the Company's interest in a secured Magma
note and general assets of the Company equal to the Restricted Payment
Recourse Amount, as defined in the Note Indenture ("Note Indenture"),
which was $0 at December 31, 1997.
At any time or from time to time on or prior to June 30, 1998, the
Company may, at its option, use all or a portion of the net cash
proceeds of a Company equity offering (as defined in the Note
Indenture) and shall at any time use all of the net cash proceeds of
any Magma equity offering (as defined in the Note Indenture) to redeem
up to an aggregate of 35% of the principal amount of the Notes
originally issued at a redemption price equal to 109.875% of the
principal amount thereof plus accrued interest to the redemption date.
On or after June 30, 2000, the Notes are redeemable at the option of
the Company, in whole or in part, initially at a redemption price of
104.9375% declining to 100% on June 30, 2002 and thereafter, plus
accrued interest to the date of redemption.
CalEnergy Credit Facility
On October 28, 1996, the Company obtained a $100,000 credit facility
(the "CalEnergy Credit Facility") of which the Company had drawn
$100,000 as of December 31, 1996. The Company has repaid the entire
balance of the CalEnergy Credit Facility.
Revolving Credit Facility
On July 8, 1996, the Company obtained a $100,000 three year revolving
credit facility. On November 26, 1997, the credit facility was
amended and increased to $400,000 and extended to November 2000. The
facility is unsecured and is available to fund working capital
requirements and finance future business expansion opportunities.
Annual Repayments of Parent Company Debt
There are no annual repayments of the parent company debt due for the
next five years.
8. Subsidiary and Project Debt:
Project loans held by subsidiaries and projects which are non recourse
to the Company comprise the following at December 31:
1997 1996
Salton Sea Notes and Bonds $ 448,754$ 538,982
Northern eurobonds 427,732 439,192
U.K. credit facility --- 128,423
CE Electric UK Funding Company Senior Notes 357,331 ---
CE Electric UK Funding Company Sterling Bonds 322,534 ---
Power Resources project debt 103,334 114,571
Coso Funding Corp. project loans 106,616 148,346
Construction loans 416,744 300,951
Other 5,962 7,927
$2,189,007 $1,678,392
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 CalEnergy's direct or indirect
subsidiaries (1) owning interests in the Coso, Imperial Valley,
Saranac, NorCon, Power Resources, Mahanagdong, Malitbog, Upper Mahiao,
Casecnan, Dieng and Patuha projects or (2) owning interests in the
subsidiaries that own interests in the foregoing projects.
Salton Sea Notes and Bonds
The Salton Sea Funding Corporation, a wholly owned subsidiary of the
Company, (the "Funding Corporation") debt securities are as follows:
Final
Maturity December 31, December 31,
Senior Secured Series Date Rate 1997 1996
July 21, 1995 A Notes May 30, 2000 6.69% $ 97,354 $161,732
July 21, 1995 B Bonds May 30, 2005 7.37% 133,000 133,000
July 21, 1995 C Bonds May 30, 2010 7.84% 109,250 109,250
June 20, 1996 D Notes May 30, 2000 7.02% 44,150 70,000
June 20, 1996 E Bonds May 30, 2011 8.30% 65,000 65,000
$448,754 $538,982
Principal and interest payments are made in semi-annual installments.
The Salton Sea Notes and Bonds are secured by the Company's four
existing Salton Sea plants as well as an assignment of the right to
receive various royalties payable to Magma in connection with its
Imperial Valley properties and distributions from the Partnership
Project. The Salton Sea Notes and Bonds are nonrecourse to the
Company.
Pursuant to a depository agreement, Funding Corporation established a
debt service reserve fund in the form of a letter of credit in the
amount of $70,430 from which scheduled interest and principal payments
can be made.
Northern Eurobonds
The Northern debt includes a debenture due in 1999, which bears a
fixed interest rate of 12.661%. The debt also includes bearer bonds
repayable in 2005 and 2020, bearing fixed interest rates of 8.625% and
8.875%, respectively.
The balance at December 31, 1997 and 1996 consists of the following:
1997 1996
Debenture due 1999 $ 97,530 $ 99,924
Bearer bonds due 2005 165,236 171,130
Bearer bonds due 2020 164,966 168,138
$ 427,732 $ 439,192
U.K. Credit Facility
On October 28, 1996, CE Holdings, an indirect subsidiary of the
Company, obtained a pound 560,000 five year term loan and revolving credit
facility (the "U.K. Credit Facility"). The Company did not guarantee,
nor was it otherwise subject to recourse for, amounts borrowed under
the U.K. Credit Facility. The agreement placed restrictions on
distributions from CE Electric to any of its shareholders based on
certain financial ratios. CE Electric has repaid the entire U.K.
Credit Facility through the use of proceeds from the senior note and
sterling bond offerings of CE Electric UK Funding Company described
below.
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 "Funding Company"), issued $125,000 of
6.853% senior notes due 2004, and $237,000 of 6.995% senior notes due
2007 (collectively, the "CE Electric UK Funding Company Senior
Notes"), and pound 200,000 of 7.25% Sterling Bonds due 2022. 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 Funding Company.
Power Resources Project Financing Debt
Power Resources, an indirect wholly-owned subsidiary, has project
financing debt consisting of a term loan payable to a consortium of
banks with interest and principal due quarterly through October 2003.
The debt carries fixed interest rates of 10.385% and 10.625%.
Coso Funding Corp. Project Loans
The Coso Funding Corp. project loans are from Coso Funding Corp., a
single-purpose corporation formed to issue notes for its own account
and act as an agent on behalf of the Coso Project. The Coso Funding
Corp. project loans carry a fixed interest rate with weighted average
interest rates of 8.65% and 8.46% at December 31, 1997 and 1996,
respectively. The loans have scheduled repayments through December
2001. The Coso Project has established irrevocable letters of credit
of $67,850 as a debt service reserve fund.
Annual Repayments of Subsidiary and Project Debt
The annual repayments of the subsidiary and project debt, excluding
construction loans, for the years beginning January 1, 1998 and
thereafter are as follows:
CE Electric UK
Salton Sea Funding Company Coso
Notes and Northern Senior Notes and Power Funding
Bonds Eurobonds Sterling Bonds Resources Corp. Other Total
1998 $ 106,938 $ --- $ --- $ 12,805 $ 38,912 $1,544 $160,199
1999 57,836 97,530 --- 14,268 31,717 1,297 202,648
2000 25,072 --- --- 16,087 4,080 1,051 46,290
2001 22,376 --- --- 18,119 31,907 838 73,240
2002 24,298 --- --- 20,312 --- 1,232 45,842
There-
after 212,234 330,202 679,865 21,743 --- --- 1,244,044
$448,754 $427,732 $679,865 $103,334 $106,616 $5,962$1,772,263
Construction Loans
The Company's allocable share of non-recourse project construction
loans comprise the following at December 31:
1997 1996
Upper Mahiao $ 150,628 $150,628
Malitbog 176,657 137,881
CE Indonesia Funding Corp. 89,459 12,442
$ 416,744 $ 300,951
The Upper Mahiao and Malitbog construction loans are scheduled to be
replaced by non-recourse term project financing upon completion of
construction and commencement of commercial operations.
Upper Mahiao Construction Loan
Draws on the construction loan for the Upper Mahiao geothermal power
project at December 31, 1997 totaled $150,628. A consortium of
international banks provided the construction financing with variable
interest rates based on LIBOR or "Prime" with interest payments due
every quarter and at LIBOR maturity. The weighted average interest
rate at December 31, 1997 and 1996 is approximately 8.43% and 8.01%,
respectively. The Export-Import Bank of the U.S. ("Ex-Im Bank") is
providing political risk insurance to commercial banks on the
construction loan. The construction loan is expected to be converted
to a term loan promptly after NPC completes the full capacity
transmission line, which is currently expected in 1998. The largest
portion of the term loan for the project will also be provided by Ex-
Im Bank. The term financing for the Ex-Im Bank loan will be at a
fixed interest rate of 5.95%.
Malitbog Construction Loan
Draws on the construction loan for the Malitbog geothermal power
project at December 31, 1997 totaled $176,657. International banks and
the Overseas Private Investment Corporation ("OPIC") have provided the
construction and term loan facilities at variable interest rates
(weighted average of 8.48% and 8.15% at December 31, 1997 and 1996,
respectively). The international bank portion of the debt will be
insured by OPIC against political risks and the Company's equity
contribution to Visayas Geothermal Power Company ("VGPC") is covered
by political risk insurance from the Multilateral Investment Guarantee
Agency and OPIC. The construction loan is expected to be converted to
a term loan promptly after NPC completes the full capacity
transmission line, which is currently expected in 1998.
CE Indonesia Funding Corp.
In June 1997, the Company's indirect special-purpose subsidiary, CE
Indonesia Funding Corp., entered into a $400,000 revolving credit
facility (which is nonrecourse to the Company) to finance the
development and construction of the Company's geothermal power
facilities in Indonesia. This credit facility was used in part to
replace the original project financing for Himpurna California
Energy's Dieng Unit I. At December 31, 1997, the Company's share of
the credit facility relating to Dieng Unit I was $50,481 and carried a
variable interest rate (weighted average of 7.44% at December 31,
1997).
On November 18, 1997, Himpurna California Energy announced the funding
of the Dieng Unit II project pursuant to the CE Indonesia Funding
Corp. facility arranged in June 1997. At December 31, 1997, the
Company's share of the credit facility relating to Dieng Unit II was
$11,211 and carried a variable interest rate (weighted average of
7.48% at December 31, 1997).
On September 2, 1997, Patuha Power announced the funding of the Patuha
Unit I project pursuant to the CE Indonesia Funding Corp. facility
arranged in June 1997. At December 31, 1997, the Company's share of
the credit facility relating to Patuha was $27,767 and carried a
variable interest rate (weighted average of 7.44% at December 31,
1997).
9. Income Taxes
Provision for income taxes is comprised of the following at December
31:
1997 1996 1995
Currently payable:
State $ 5,084$ 7,520 $5,510
Federal 33,114 19,873 11,138
Foreign 5,262 2,176 ---
43,460 29,569 16,648
Deferred:
State (264) 1,619 921
Federal 14,579 9,209 13,062
Foreign 41,269 1,424 ---
55,584 12,252 13,983
Total $ 99,044 $41,821 $30,631
A reconciliation of the federal statutory tax rate to the effective
tax rate applicable to income before provision for income taxes
follows:
1997 1996 1995
Federal statutory rate 35.00% 35.00% 35.00%
Percentage depletion in excess of cost depletion (3.77) (6.12) (7.38)
Investment and energy tax credits (.64) (8.34) (1.80)
State taxes, net of federal tax effect 1.59 4.38 4.09
Goodwill amortization 2.06 2.51 2.53
Non-deductible expense 1.33 .84 1.10
Lease investment --- --- (2.18)
Dividends on convertible preferred securities
of subsidiary trusts* (4.12) (1.17) ---
Tax effect of foreign income 2.64 2.54 ---
Asset valuation impairment 15.47 --- ---
Other .75 .15 .20
Effective tax rate 50.31% 29.79% 31.56%
* Dividends on convertible preferred securities of subsidiary trusts
are included in minority interest.
Deferred tax liabilities (assets) are comprised of the following at
December 31:
1997 1996
Depreciation and amortization, net $ 802,215 $ 725,366
Pensions 19,441 22,883
Unremitted foreign earnings 10,781 2,857
Other 3,324 3,262
835,761 754,368
Deferred contract costs (193,996) (128,745)
Deferred income (12,690) (9,298)
Energy and investment tax credits (42,049) (55,931)
Advance corporation tax --- (20,205)
Alternative minimum tax credits (39,402) (50,819)
Accruals not currently deductible for tax purposes (31,561) (13,372)
Other (7,004) (6,799)
(326,702) (285,169)
Net deferred taxes $509,059 $469,199
The Company has unused investment and geothermal energy tax credit
carryforwards of approximately $42,049 expiring between 2004 and 2012.
The Company also has approximately $39,402 of alternative minimum tax
credit carryforwards which have no expiration date.
10. Company-Obligated Mandatorily Redeemable Convertible Preferred
Securities of Subsidiary Trusts
The Company has organized special purpose Delaware business trusts
("Trust I", "Trust II" and "Trust III" or collectively, the "Trusts")
pursuant to their respective amended and restated declarations of
trusts (collectively, the "Declarations"). On April 12, 1996,
February 26, 1997 and August 12, 1997, the Company, through these
Trusts, issued Company-obligated mandatorily redeemable convertible
preferred securities (collectively, the "Trust Securities") as
follows:
Issuer Issue Date Rate Amount Conversion Rate
CalEnergy Capital Trust I April 12,1996 6.25% $103,930 1.6728
CalEnergy Capital Trust II February 26,1997 6.25% $180,000 1.1655
CalEnergy Capital Trust III August 12, 1997 6.50% $270,000 1.047
The Company owns all of the common securities of the Trusts. The Trust
Securities have a liquidation preference of fifty dollars each and
represent undivided beneficial ownership interests in each of the
Trusts. The assets of the Trusts consist solely of the Company's
Convertible Subordinated Debentures due March 10, 2016, February 25,
2012 and September 1, 2027, respectively, in outstanding aggregate
principal amounts of $103,930, $180,000 and $270,000, respectively
(collectively, the "Junior Debentures") issued pursuant to their
respective indentures. The indentures include agreements by the
Company to pay expenses and obligations incurred by the Trusts. Each
Trust Security with a par value of $50 is convertible at the option of
the holder at any time into shares of CalEnergy Common Stock based on
the conversion rate and subject to customary anti-dilution
adjustments.
Until converted into the Company's Common Stock, the Trust Securities
will have no voting rights with respect to the Company and, except
under certain limited circumstances, will have no voting rights with
respect to the Trusts. Distributions on the Trust Securities (and
Junior Debentures) are cumulative, accrue from the date of initial
issuance and are payable quarterly in arrears. The Junior Debentures
are subordinated in right of payment to all senior indebtedness of the
Company and the Junior Debentures are subject to certain covenants,
events of default and optional and mandatory redemption provisions,
all as described in the Junior Debenture indentures.
Pursuant to Preferred Securities Guarantee Agreements (collectively,
the "Guarantees"), between the Company and a preferred guarantee
trustee, the Company has agreed irrevocably to pay to the holders of
the Trust Securities, to the extent that the Trustee has funds
available to make such payments, quarterly distributions, redemption
payments and liquidation payments on the Trust Securities. Considered
together, the undertakings contained in the Declarations, Junior
Debentures, Indentures and Guarantees constitute full and
unconditional guarantees by the Company of the Trusts' obligations
under the Trust Securities.
11.Preferred Stock
On December 1, 1988, the Company distributed a dividend of one
preferred share purchase right ("right") for each outstanding share of
common stock. The rights are not exercisable until ten days after a
person or group acquires or has the right to acquire, beneficial
ownership of 20% or more of the Company's common stock or announces a
tender or exchange offer for 30% or more of the Company's common
stock. Each right entitles the holder to purchase one one-hundredth of
a share of Series A junior preferred stock for $52. The rights may be
redeemed by the Board of Directors up to ten days after an event
triggering the distribution of certificates for the rights. The
rights will expire, unless previously redeemed or exercised, on
November 30, 1998. The rights are automatically attached to, and trade
with, each share of common stock.
12.Stock Options and Restricted Stock
The Company has issued various stock options. As of December 31, 1997,
a total of 6,949 shares are reserved for stock options, of which 6,780
shares have been granted and remain outstanding at prices of $3.74 to
$40.81 per share.
The Company has stock option plans under which shares were reserved
for grant as incentive or non-qualified stock options, as determined
by the Board of Directors. The plans allow options to be granted at
85% of their fair market value at the date of grant. Generally,
options are issued at 100% of fair market value at the date of grant.
Options granted under the 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. Prior to the
1996 Plan, the Company granted 256 options at fair market value at
date of grant which had terms of ten years and were exercisable at
date of grant. In addition, the Company had issued approximately 138
options to consultants on terms similar to those issued under the 1996
Plan. The non-1996 plan options are primarily options granted to
Kiewit.
The Company granted 500 shares of restricted common stock with an
aggregate market value of $9,500 in exchange for the relinquishment of
500 stock options which were canceled by the Company. The shares have
all rights of a shareholder, subject to certain restrictions on
transferability and risk of forfeiture. Unearned compensation
equivalent to the market value of the shares at the date of issuance
was charged to stockholders' equity. Such unearned compensation was
amortized over the vesting period of which 125 shares were immediately
vested and the remaining 375 shares vested through January 1, 1998.
Accordingly, $5,471, $1,535 and $2,494 of unearned compensation was
charged to general and administrative expense in 1997, 1996 and 1995,
respectively.
Transactions in Stock Options
Options Outstanding
Shares Available
for Grant Under Option Price Weighted Avg
1996 Option Plan Shares Per Shares Option Price Total
Balance December 31, 1994 86 9,601 $3.00 - $19.00 $12.84 $123,277
Options granted (396) 396 15.81 - 19.00 18.15 7,188
Options terminated 571 (571)14.88 - 19.00 18.69 (10,673)
Options exercised --- (135) 3.00 - 15.94 3.41 (460)
Balance
December 31,1995 261 9,291 3.00 - 19.00 12.84 119,332
Options granted (1,157) 1,157 25.06 - 30.38 28.17 32,590
Options terminated 468 (468) 3.00 - 19.00 17.96 (8,406)
Options exercised --- (5,203) 3.00 - 21.68 11.13 (57,931)
Additional shares
reserved under 1996
Option Plan 739 --- --- --- ---
Balance
December 31, 1996 311 4,777 3.00 - 30.38 17.928 5,585
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
Options exercisable at:
December 31, 1995 8,229 $3.00 -$19.00 $12.26 $100,886
December 31, 1996 3,071 $3.00 -$30.38 $14.25 $ 43,770
December 31, 1997 3,665 $3.74 -$40.19 $18.12 $ 66,425
The following table summarizes information about stock options outstanding
and exercisable as of December 31, 1997:
Options Outstanding Options Exercisable
Weighted Weighted Weighted
Range of Number Average Average Remaining Number Average
Exercise Outstanding Exercise Contractual Life Exercisable Exercise
Prices Price Price
$3.74 $11.99 1,161 $ 11.22 3 years 1,161 $ 11.22
12.00 21.99 2,020 16.90 6 years 1,739 16.82
22.00 31.99 1,092 28.10 8 years 311 28.25
32.00 40.81 2,507 34.83 9 years 454 34.12
6,780 $ 24.36 7 years 3,665 $ 18.12
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 for 1997, non-cash compensation expense and
the effect on net income available to common stockholders and earnings
per share would have been approximately $3,600, or $0.05 per share.
If the fair value based method had been applied for 1996 and 1995, non-
cash compensation expense and the effect on net income available to
common stockholders and earnings per share would have been immaterial.
The fair value for stock options was estimated using the Black-Scholes
option pricing model with assumptions for the risk-free interest rate
of 5.50% in 1997 and 6.00% in 1996 and 1995, expected volatility of
25% in 1997 and 22% in 1996 and 1995, expected life of approximately
3.7 years in 1997 and 4.5 years in 1996 and 1995, and no expected
dividends. The weighted average fair value of options granted during
1997, 1996 and 1995 was $9.55, $8.62 and $5.72 per option,
respectively.
13.Common Stock Sales & Related Options
On October 17, 1997, the Company completed the public offering of
17,100 shares of its common stock ("Common Stock") at $37 7/8 per
share (the "Public Offering"). In addition, 2,000 shares of Common
Stock were purchased from CalEnergy in a direct sale by a trust
affiliated with Walter Scott, Jr., the Chairman and Chief Executive
Officer of PKS (the "Direct Sale"), contemporaneously with the closing
of the Public Offering. Proceeds from the Public Offering and the
Direct Sale were approximately $699,920.
Simultaneous with the acquisition of the remaining equity interest of
Magma on February 24, 1995, the Company completed a public offering
(the "Offering") of 18,170 shares of common stock, which amount
included a direct sale by the Company to Kiewit of 1,500 shares and
the exercise of underwriter over-allotment options for 1,500 shares,
at a price of $17.00 per share. The Company received proceeds of
$300,388 from the Offering.
14.Asset Valuation Impairment Charge
The non-recurring charge of $87,000 represents an asset valuation
impairment charge under Financial Accounting Standard No. 121,
"Accounting for the Impairment of Long-Lived Assets," relating to
CalEnergy's assets in Indonesia. Moreover, the Company intends to
continue to take actions to attempt to require the Government of
Indonesia to honor its contractual obligations; however, the ultimate
outcome of the current uncertain situation in Indonesia with respect
to the possible abrogation by the Indonesian government of the Dieng,
Patuha and Bali contracts adds significant risk to the completion of
those projects. Consequently, the charge of $87,000 represents the
amount by which the carrying amount of such assets exceed the fair
value of the assets determined by discounting the expected future net
cash flows of the Indonesia projects, assuming proceeds from political
risk insurance and no tax benefits.
15. Extraordinary Item
On July 31, 1997, the Finance Act in the United Kingdom was passed by
Parliament and included the introduction of a one time so-called
"windfall tax" equal to 23% of the difference between the price paid
for Northern upon privatization and the Labour government's assessed
"value" of Northern as calculated by reference to a formula set forth
in the July budget. This amounted to $135,850, net of minority
interest of $58,222, which was recorded as an extraordinary item. The
first installment was paid December 1, 1997 and the second installment
is payable on December 1, 1998.
16.Fair Value of Financial Instruments
The fair value of a financial instrument is the amount at which the
instrument could be exchanged in a current transaction between willing
parties, other than in a forced sale or liquidation. Although
management uses its best judgment in estimating the fair value of
these financial instruments, there are inherent limitations in any
estimation technique. Therefore, the fair value estimates presented
herein are not necessarily indicative of the amounts which the Company
could realize in a current transaction.
The methods and assumptions used to estimate fair value are as
follows:
Debt instruments - The fair value of all debt issues listed on
exchanges has been estimated based on the quoted market prices.
Other financial instruments - All other financial instruments of a
material nature fall into the definition of short-term and fair value
is estimated as the carrying amount.
The carrying amounts in the table below are included under the
indicated captions in Notes 7, 8 and 10.
1997 1996
Estimated Estimated
Carrying Fair Carrying Fair
Value Value Value Value
Senior discount notes $529,640 $569,148 $527,535 $556,971
9.5% Senior notes 224,205 243,615 224,150 229,866
7.63% Senior notes 350,000 352,857 --- ---
Limited recourse senior secured notes 200,000 217,829 200,000 212,560
CalEnergy credit facility --- --- 100,000 100,000
Revolving line of credit --- --- 95,000 95,000
Salton Sea notes and bonds 448,754 463,720 538,982 531,807
Northern eurobonds 427,732 482,064 439,192 445,830
Construction loans 416,744 416,744 300,951 300,951
Coso Funding Corp. project loans 106,616 112,932 148,346 153,650
CE Electric UK Funding Company Senior Notes 357,331 357,331 --- ---
CE Electric UK Funding Company Sterling Bonds322,534 333,257 --- ---
Power Resources project debt 103,334 103,334 114,571 114,571
U.K. credit facility --- --- 128,423 128,423
Other 5,962 5,962 7,927 7,927
Convertible preferred securities of
subsidiary trusts 553,930 514,373 103,930 128,354
17. Interest Rate Swap Agreements
On December 15, 1997, CE Electric UK Funding Company entered into
certain interest rate swap agreements for the CE Electric UK Funding
Company Senior Notes with two large multi-national financial
institutions. The swap agreements effectively convert the U.S. dollar
fixed interest rate to a fixed rate in Sterling. For the $125,000 of
6.853% senior notes, the agreements extend until December 30, 2004 and
convert the U.S. dollar interest rate to a fixed Sterling rate of
7.744%. For the $237,000 of 6.995% senior notes, the agreements
extend until December 30, 2007 and convert the U.S. dollar interest
rate to a fixed Sterling rate of 7.737%. The estimated fair value of
these swap agreements is approximately $4,929 based on quotes from the
counter party to these instruments and represents the estimated amount
that the Company would expect to pay to terminate these agreements.
It is the Company's intention to hold the swap agreements to their
intended maturity.
18. Regulatory Matters
Northern is subject to price cap regulation. Price control formulas
for the supply and distribution businesses are enforced by the Office
of Electricity Regulation ("OFFER").
In the distribution business the current price control is expected to
last until 2000. The formula was reviewed with effect from April 1,
1995 and April 1, 1996 which resulted in one-time reductions in
allowed income per unit distributed of about 17% and 13% respectively,
with continuing real reductions in each of the subsequent three years
1997/98 to 1999/2000. The current formula requires that each year
regulated distribution income per unit is increased or decreased by
RPI-Xd where RPI reflects the average of the twelve month inflation
rates recorded for the previous July to December period and Xd is set
at 3%. The formula also takes account of the changes in system
electrical losses, the number of customers connected and the voltage
at which customers receive the units of electricity distributed.
In the supply business the current formula applies only to customers
with demands below 100kW. Under the current formula the purchase cost
of electricity and the cost of transmission, distribution and the
fossil fuel levy are passed through to customers in full. That part
of the formula governing Northern's own supply business costs requires
that this element of the permitted income falls by 2% per annum in
real terms. The current formula is due to be replaced from April 1,
1998 with a new formula which will require Northern to reduce prices
to those customers protected by the new price control from the level
prevailing at August 1, 1997 by about 4.2% (minus inflation) with
effect from April 1, 1998 and a further 3% (minus inflation) with
effect from April 1, 1999.
The market for electricity supplied to customers with demands over 1MW
was opened to competition in 1990. In 1994 this limit was reduced to
0.1MW. In 1998, liberalization of the entire market is due to
commence in stages with complete liberalization achieved by June 1999.
19. Pension Commitments
Northern participates in the Electricity Supply Pension Scheme, which
provides pension and other related defined benefits, based on final
pensionable pay, to substantially all employees throughout the
Electricity Supply Industry in the United Kingdom.
The actuarial computation for December 31, 1997 and 1996 assumed
interest rates of 6.75% and 7.75%, respectively, an expected return on
plan assets of 7.25% and 8.25%, respectively, and annual compensation
increases of 4.75% and 5.75%, respectively, over the remaining service
lives of employees covered under the plan. Amounts funded to the
pension are primarily invested in equity and fixed income securities.
Northern's funding policy for the plan is to contribute annually at a
rate that is intended to remain a level percentage of compensation for
the covered employees.
The following table details the funded status and the amount
recognized in the balance sheet of the Company as of December 31,
1997 and 1996.
Actuarial present value of benefit obligations: 1997 1996
Vested benefits $ 847,694 $ 797,932
Nonvested benefits --- ---
Accumulated benefit obligation 847,694 797,932
Effect of future increase in compensation 40,898 58,218
Projected benefit obligation 888,592 856,150
Fair value of plan assets 1,012,601 919,163
Assets in excess of projected benefit obligation 124,009 63,013
Unrecognized net gain 61,265 ---
Prepaid pension asset $ 62,744 $ 63,013
Net periodic pension cost for 1997 included the following components
(the components for the period from the acquisition date of Northern
to December 31, 1996 are not meaningful):
Service cost - benefits earned during the period$ 12,600
Interest cost on projected benefit obligation 62,300
Actual return on plan assets (71,300)
Net periodic pension cost $ 3,600
20. Commitments and Contingencies
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.
CE Casecnan Water and Energy Company, Inc., a Philippine Corporation
("CE Casecnan") which is expected to be approximately 70% indirectly
owned by the Company (after the KDG Acquisition), is developing the
Casecnan Project. CE Casecnan financed a portion of the costs of the
Casecnan Project through the issuance of $125,000 of its 11.45% Senior
Secured Series A Notes due 2005 and $171,500 of its 11.95% Senior
Secured Series B Bonds due 2010 and $75,000 of its Secured Floating
Rate Notes due 2002, pursuant to an indenture dated as of November 27,
1995, as amended to date.
The Casecnan Project was being constructed pursuant to a fixed-price,
date-certain, turnkey construction contract (the "Hanbo Contract") on
a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo
Engineering and Construction Co., Ltd. ("HECC"), both of which are
South Korean corporations. As of May 7, 1997, CE Casecnan terminated
the Hanbo Contract due to defaults by Hanbo and HECC including the
insolvency of each such company. On May 7, 1997 CE Casecnan entered
into a new turnkey engineering, procurement and construction contract
to complete the construction of the Casecnan Project (the "Replacement
Contract"). The work under the Replacement Contract is being
conducted by a consortium consisting of Cooperativa Muratori
Cementisti CMC di Ravenna and Impressa Pizzarottie & C. Spa working
together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and
Colenco Power Engineering Ltd. (collectively, the "Replacement
Contractor").
In connection with the Hanbo Contract termination, CE Casecnan
tendered a certificate of drawing to Korea First Bank ("KFB") on May
7, 1997 under the irrevocable standby letter of credit issued by KFB
as security under the Hanbo Contract to pay for certain transition
costs and other presently ascertainable damages under the Hanbo
Contract. As a result of KFB's wrongful dishonor of the draw request,
CE Casecnan filed an action in New York State Court. That Court
granted CE Casecnan's request for a temporary restraining order
requiring KFB to deposit $79,329, the amount of the requested draw, in
an interest bearing account with an independent financial institution
in the United States. KFB appealed this order, but the appellate
court denied KFB's appeal and on May 19, 1997, KFB transferred funds
in the amount of $79,329 to a segregated New York bank account
pursuant to the Court order. If KFB were to fail to honor its
obligations under the Casecnan letter of credit, such action could
have a material adverse effect on the Casecnan Project and CE
Casecnan.
On August 6, 1997, CE Casecnan announced that it had issued a notice
to proceed to the Replacement Contractor. The Replacement Contractor
was already on site and has fully mobilized and commenced engineering,
procurement and construction work on the Casecnan Project.
On August 27, 1997, CE Casecnan announced that it had received a
favorable summary judgment ruling in New York State Court against KFB.
The judgment, which has been appealed by the bank, requires KFB to
honor the $79,329 drawing by CE Casecnan on the $117,850 irrevocable
standby letter of credit.
On September 29, 1997, CE Casecnan tendered a second certificate of
drawing for $10,828 to KFB and on December 30, 1997, CE Casecnan
tendered a third certificate of drawing for $2,920 to KFB. KFB also
wrongfully dishonored these draws, but pursuant to a stipulation
agreed to deposit the draw amounts in an interest bearing account with
the same independent financial institution in the United States
pending resolution of the appeal regarding the first draw and agreed
to expedite the appeal.
The receipt of the letter of credit funds from KFB remains essential
and CE Casecnan will continue to press KFB to honor its clear
obligations under the letter of credit and to pursue Hanbo and KFB for
any additional damages arising out of their actions to date. If KFB
were to fail to honor its obligations under the Casecnan letter of
credit, such action could have a material adverse effect on the
Casecnan Project and CE Casecnan.
On September 2, 1997, Hanbo and HECC filed a Request for Arbitration
before the International Chamber of Commerce ("ICC"). The Request for
Arbitration asserts various claims by Hanbo and HECC against CE
Casecnan relating to the terminated Hanbo Contract and seeking
damages. On October 10, 1997, CE Casecnan served its answer and
defenses in response to the Request for Arbitration as well as
counterclaims against Hanbo and HECC for breaches of the Hanbo
Contract. The arbitration proceedings before the ICC are ongoing and
CE Casecnan intends to pursue vigorously its claims against Hanbo,
HECC and KFB in the proceedings described above.
Indonesia
On September 20, 1997, a Presidential Decree (the "Decree") was issued
in Indonesia, providing for government action to the effect that, in
order to address certain recent fluctuations in the value of the
Indonesian currency, the start-up dates for a number of private power
projects would be: (i) continued according to their initial schedule
(because construction was underway); (ii) postponed as to their start-
up dates (because they are not yet in construction) until economic
conditions have recovered; or (iii) reviewed with a view to being
continued, postponed or rescheduled, depending on the status of those
projects. In the Decree, Dieng Units 1, 2 and 3 are approved to
continue according to their initial schedule; Patuha Unit 1 and Bali
Units 1 and 2 are to receive further review to determine whether or
not they should be continued in accordance with their initial
schedule; and Bali Units 3 and 4, Patuha Units 2, 3 and 4 and Dieng
Unit 4 are to be postponed for an unspecified period. In this regard,
the Company notes that its contracts and government undertakings for
the Dieng, Patuha and Bali projects do not by their terms permit such
categorization or delays by the government and that the Company has
obtained political risk insurance coverage for its Dieng and Patuha
projects. Moreover, the Company intends to continue to take actions to
attempt to require the Government of Indonesia to honor its
contractual obligations; however, subsequent actions by the Government
of Indonesia and continued economic problems in Indonesia have created
further uncertainty as to whether the contracts for such projects will
be abrogated by the Indonesian government and accordingly have created
significant risks to the completion of these projects. As a result,
the Company recorded a SFAS 121 asset valuation impairment charge of
$87,000 in the fourth quarter of 1997. This charge includes all
reasonably estimated asset valuation impairments associated with the
Company's assets in Indonesia and gives effect to the political risk
insurance on such investments.
Edison
On June 9, 1997, Edison filed a complaint alleging breach of the power
purchase agreements ("SO4 Agreements") between Edison and the Coso
Joint Ventures as a result of alleged improper venting of certain
noncondensible gases at the Coso geothermal energy project. In the
complaint Edison seeks unspecified damages, including the refund of
certain amounts previously paid under the SO4 Agreements, and
termination of the SO4 Agreements. In September 1997, the Coso Joint
Ventures and the Company filed a cross-complaint against Edison and
its affiliates, The Mission Group and Mission Power Engineering
Company alleging, among other things, that Edison's lawsuit violates
the 1993 settlement agreement which settled certain litigation arising
from the construction of certain units at the Coso geothermal project
by Edison affiliates. In addition, the Coso Joint Ventures filed a
separate complaint against Edison alleging breach of the SO4
Agreements, unfair business practices, slander and various other tort
and contract claims. The actions were effectively consolidated in
December 1997. As a result of certain procedural actions by the
parties and a November court order, Edison filed an amended complaint
on December 16, 1997 and the Coso Joint Ventures amended their cross-
complaint. The litigation is in its early procedural stages and the
pleadings have not been settled. The Coso Joint Ventures believe that
their claims and defenses are meritorious and that they will prevail
if the matter is ultimately heard on its merits. The Coso Joint
Ventures intend to vigorously defend this action and prosecute all
available counterclaims against Edison.
NYSEG
On February 14, 1995, NYSEG filed with the FERC a Petition for a
Declaratory Order, Complaint, and Request for Modification of Rates in
Power Purchase Agreements Imposed Pursuant to the Public Utility
Regulatory Policies Act of 1978 ("Petition") seeking FERC (i) to
declare that the rates NYSEG pays under the Saranac PPA, which was
approved by the New York Public Service Commission (the "PSC") were in
excess of the level permitted under PURPA and (ii) to authorize the
PSC to reform the Saranac PPA. On March 14, 1995, the Saranac
Partnership intervened in opposition to the Petition asserting, inter
alia, that the Saranac PPA fully complied with PURPA, that NYSEG's
action was untimely and that the FERC lacked authority to modify the
Saranac PPA. On March 15, 1995, the Company intervened also in
opposition to the Petition and asserted similar arguments. On April
12, 1995, the FERC by a unanimous (5-0) decision issued an order
denying the various forms of relief requested by NYSEG and finding
that the rates required under the Saranac PPA were consistent with
PURPA and the FERC's regulations. On May 11, 1995, NYSEG requested
rehearing of the order and, by order issued July 19, 1995, the FERC
unanimously (5-0) denied NYSEG's request. On June 14, 1995, NYSEG
petitioned the United States Court of Appeals for the District of
Columbia Circuit (the "Court of Appeals") for review of FERC's April
12, 1995 order. FERC moved to dismiss NYSEG's petition for review on
July 28, 1995. On October 30, 1996, all parties filed final briefs
and the Court of Appeals heard oral arguments on December 2, 1996. On
July 11, 1997, the Court of Appeals dismissed NYSEG's appeal from
FERC's denial of the petition on jurisdictional grounds.
On August 7, 1997, NYSEG filed a complaint in the U.S. District Court
for the Northern District of New York against the FERC, the PSC (and
the Chairman, Deputy Chairman and the Commissioners of the PSC as
individuals in their official capacity), the Saranac Partnership and
Lockport Energy Associates, L.P. ("Lockport") concerning the power
purchase agreements that NYSEG entered into with Saranac Partners and
Lockport.
NYSEG's suit asserts that the PSC and the FERC improperly implemented
PURPA in authorizing the pricing terms that NYSEG, the Saranac
Partnership and Lockport agreed to in those contracts. The action
raises similar legal arguments to those rejected by the FERC in its
April and July 1995 orders. NYSEG in addition asks for retroactive
reformation of the contracts as of the date of commercial operation
and seeks a refund of $281 million from the Saranac Partnership.
Saranac and other parties have filed motions to dismiss and oral
arguments on those motions were heard on March 2, 1998. Saranac
believes that NYSEG's claims are without merit for the same reasons
described in the FERC's orders.
Leases
Certain retail facilities, buildings and equipment are leased. The
leases expire in periods ranging from one to 75 years and some provide
for renewal options.
At December 31, 1997, the Company's future minimum rental payments
with respect to non-cancelable operating leases were as follows:
1998 $ 5,321
1999 4,970
2000 4,914
2001 4,742
2002 4,643
Thereafter 53,905
$ 78,495
21. Geographic Information
The Company operates in one principal industry segment: the
generation, distribution and supply of electricity to customers
located throughout the world. Europe consists primarily of Northern.
The Company's operations by geographic area are as follows:
1997 1996 1995
Revenue
Americas $ 570,587$ 486,189 $ 386,833
Asia 102,960 33,282 ---
Europe 1,566,442 39,191 ---
Corporate/Other 30,922 17,533 11,890
$2,270,911 $ 576,195 $ 398,723
Operating income *
Americas $ 301,589 $ 259,665 $ 209,872
Asia 61,131 16,766 ---
Europe 191,299 6,163 ---
Corporate/Other (12,882) (10,931) (10,376)
$ 541,137 $ 271,663 $ 199,496
* Operating income excludes the loss on equity investment in Casecnan,
net interest expense and the non-recurring charge.
1997 1996
Identifiable assets
Americas $ 2,268,629 $ 2,364,448
Asia 835,616 649,053
Europe 2,937,686 2,384,789
Corporate/Other 1,445,695 231,866
$ 7,487,626 $ 5,630,156
22. QUARTERLY FINANCIAL DATA (UNAUDITED)
Following is a summary of the Company's quarterly results of
operations for the years ended December 31, 1997 and 1996.
Three
Months
Ended *
1997: (1) March 31 June 30 September 30 December 31
Operating revenue $542,589 $505,922 $527,896 $589,931
Total revenue 565,976 524,994 551,893 628,048
Total costs and 506,104 460,184 467,900 639,863
expenses
Income (loss) before 59,872 64,810 83,993 (11,815)
income taxes 22,249 24,342 27,929 24,524
Provision for income
taxes
Income (loss) before 37,623 40,468 56,064 (36,339)
minority interest 10,175 9,579 9,656 16,583
Minority interest
Income (loss) before 27,448 30,889 46,408 (52,922)
extraordinary item --- --- (135,850) ---
Extraordinary item
Net income (loss)
attributable to 27,448 30,889 (89,442) (52,922)
common stockholders
Income (loss) per
share before extraordinary
item $ .43 $ .49 $ .73 $ (.67)
Extraordinary item --- --- (2.14) ---
Net income (loss) per
share $ .43 $ .49 $ (1.41) $ (.67)
Income (loss) per
share before
extraordinary item - $ .42 $ .46 $ .67 $ (.67)
diluted --- --- (1.80) ---
Extraordinary item -
diluted
Net income (loss) per
share - diluted $ .42 $ .46 $ (1.13) $ (.67)
Three Months Ended
*
1996: (112) March 31 June 30 September 30 December 31
Operating revenue $ 75,944 $104,735 $165,487 $172,768
Total revenue 90,356 115,794 179,048 190,997
Total costs and 69,398 86,039 121,545 158,809
expenses
Income before income 20,958 29,755 57,503 32,188
taxes 6,497 9,040 18,325 7,959
Provision for income
taxes
Income before minority 14,461 20,715 39,178 24,229
interest --- 1,443 1,624 3,055
Minority interest
Net income attributable
to common stockholders $14,461 $19,272 $37,554 $ 21,174
Net income per share $ .28 $ .37 $ .71 $ .34
Net income per share -
diluted $ .27 $ .34 $ .61 $ .33
* The Company's operations are seasonal in nature.
(1) Reflects acquisitions of Northern, Falcon Seaboard and the
Partnership Interest.
INDEPENDENT AUDITORS' REPORT
Board of Directors and Shareholders
CalEnergy Company, Inc.
Omaha, Nebraska
We have audited the accompanying consolidated balance sheets of
CalEnergy Company, Inc. and subsidiaries as of December 31, 1997
and 1996, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in
the period ended December 31, 1997. These financial statements are
the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
CalEnergy Company, Inc. and subsidiaries at December 31, 1997 and
1996 and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Omaha, Nebraska
February 12, 1998
EXHIBIT 21
CALENERGY COMPANY, INC.
SUBSIDIARIES AND JOINT VENTURES
Corporations:
COSO HOTSPRINGS INTERMOUNTAIN POWER, INC. Delaware
CHINA LAKE OPERATING COMPANY Delaware
COSO TECHNOLOGY CORPORATION Delaware
COSO FUNDING CORP. Delaware
CHINA LAKE GEOTHERMAL MANAGEMENT COMPANY Delaware
CHINA LAKE PLANT SERVICES, INC. California
COSO HOTSPRINGS OVERLAND POWER, INC. Delaware
CE GEOTHERMAL, INC. Delaware
WESTERN STATES GEOTHERMAL COMPANY Delaware
INTERMOUNTAIN GEOTHERMAL COMPANY Delaware
CE CIS-FSU, Inc. Delaware
CALENERGY DEVELOPMENT CORPORATION Delaware
CALIFORNIA ENERGY YUMA CORPORATION Utah
ROSE VALLEY PROPERTIES, INC. Delaware
CBE ENGINEERING CO. California
CE EXPLORATION COMPANY Delaware
CE NEWBERRY, INC. Delaware
CE HUMBOLDT, INC. Delaware
CALENERGY INTERNATIONAL SERVICES, INC. Delaware
AMERICAN PACIFIC FINANCE COMPANY Delaware
CALIFORNIA ENERGY GENERAL CORPORATION Delaware
GILBERT/CBE INDONESIA L.L.C. 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
HIMPURNA CALIFORNIA ENERGY LTD. Bermuda
CE COLOMBIA LTD. Bermuda
BALI ENERGY LTD. Bermuda
CE CASECNAN LTD. Bermuda
CE LATIN AMERICA LTD. Bermuda
PATUHA POWER, LTD. Bermuda
CE SINGAPORE LTD. Bermuda
CALENERGY INTERNATIONAL LTD. Bermuda
CE CASECNAN WATER AND ENERGY COMPANY, INC. Philippines
CE BALI LTD. Bermuda
CE IJEN LTD. Bermuda
CE ASIA LTD. Bermuda
CE OVERSEAS LTD. Bermuda
MAGMA POWER COMPANY Nevada
DESERT VALLEY COMPANY California
VULCAN POWER COMPANY Nevada
CALENERGY OPERATING CORPORATION Delaware
SALTON SEA POWER COMPANY Nevada
IMPERIAL MAGMA Nevada
MAGMA LAND COMPANY I Nevada
MAGMA GENERATING COMPANY II Nevada
MAGMA GENERATING COMPANY I Nevada
PEAK POWER CORPORATION California
FISH LAKE POWER COMPANY Delaware
CALIFORNIA ENERGY MANAGEMENT COMPANY Delaware
SALTON SEA FUNDING CORPORATION Delaware
SALTON SEA ROYALTY COMPANY Delaware
TONGONAN POWER INVESTMENT, INC. Philippines
MAGMA NETHERLANDS B.V. Netherlands
NORMING INVESTMENTS B.V. Netherlands
CALIFORNIA ENERGY RETAIL COMPANY, INC. Delaware
CALENERGY IMPERIAL VALLEY COMPANY, INC. Delaware
SLUPO I B.V. Netherlands
BN GEOTHERMAL INC. Delaware
CONEJO ENERGY COMPANY California
NIGUEL ENERGY COMPANY California
SAN FELIPE ENERGY COMPANY California
BIOCLEAN FUELS INC. Delaware
CE/FS HOLDING COMPANY, INC. Delaware
CALENERGY BCF, INC. Delaware
CE ALBERTA BIOCLEAN, INC. Delaware
AMERICAN PACIFIC FINANCE COMPANY II Delaware
FALCON SEABOARD RESOURCES, INC. Texas
FALCON SEABOARD ENERGY CORPORATION Texas
FALCON SEABOARD OIL COMPANY Texas
FALCON SEABOARD PIPELINE CORPORATION Texas
FALCON SEABOARD POWER CORPORATION Texas
FALCON SEABOARD GAS COMPANY Texas
POWER RESOURCES, INC. 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
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 INFORMATION SYSTEMS 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
CALENERGY MINERALS, INC. Delaware
CE INDONESIA FUNDING CORP. Delaware
CEABC CO. Delaware
CEXYZ CO. Delaware
CE ELECTRIC (NY), INC. New York
NEPTUNE POWER LTD England/Wales
CALENERGY GAS (POLSKA) SP. Z O.O. Poland
CE (BERMUDA) FINANCING LTD. Bermuda
CALENERGY GAS (PIPELINES) LIMITED England/Wales
POLSKA POWER SP. Z O.O. Poland
SALTON SEA POWER L.L.C. Delaware
KIEWIT ENERGY COMPANY 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 I, L.L.C. Delaware
CE AURORA I, INC. Delaware
NORTHERN AURORA, INC. Delaware
CALENERGY MINERALS LLC Delaware
Joint Ventures/Partnerships:
COSO ENERGY DEVELOPERS California
COSO FINANCE PARTNERS California
COSO POWER DEVELOPERS California
COSO TRANSMISSION LINE PARTNERS California
COSO FINANCE PARTNERS II California
COSO LAND COMPANY California
CHINA LAKE JOINT VENTURE California
COSO GEOTHERMAL COMPANY California
YUMA COGENERATION ASSOCIATES Utah
GILBERT/CBE, L.P. Nebraska
VULCAN/BN GEOTHERMAL POWER COMPANY Nevada
LEATHERS, L.P. California
ELMORE, L.P. California
DEL RANCH, L.P. (HOCH) California
SALTON SEA BRINE PROCESSING, L.P. California
SALTON SEA POWER GENERATION L.P. California
ALTO PEAK POWER COMPANY Philippines
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
SEAL SANDS NETWORK LIMITED England/Wales
CE ELECTRIC UK FUNDING COMPANY England/Wales
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement No. 33-41152, No. 33-52147 and No. 333-30395 on Form S-
8 and Registration Statement No. 33-51363 and No. 333-32821 on
Form S-3 of CalEnergy Company, Inc. of our reports dated February
12, 1998, appearing in and incorporated by reference in the
Annual Report on Form 10-K of CalEnergy Company, Inc. for the
year ended December 31, 1997.
DELOITTE & TOUCHE L.L.P.
Omaha, Nebraska
March 27, 1998
Exhibit 24
POWER OF ATTORNEY
The undersigned, a member of the Board of Directors of
CalEnergy Company, Inc., a Delaware corporation (the "Company"),
hereby constitutes and appoints Steven A. McArthur, Craig M.
Hammett 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, 1997
and to execute any amendments thereto and to file the same, with
all exhibits thereto, and all other documents in connection
therewith, with the Securities and Exchange Commission and
applicable stock exchanges, with the full power and authority to
do and perform each and every act and thing necessary or
advisable to all intents and purposes as he/she might or could do
in person, hereby ratifying and confirming all that said attorney-
in-fact and agent, or his/her substitute or substitutes, may
lawfully do or cause to be done by virtue hereof.
POWER OF ATTORNEY
Executed as of March 27, 1998
/s/ David L. Sokol /s/ David R. Morris
DAVID L. SOKOL DAVID R. MORRIS
/s/ Edgar D. Aronson /s/ Bernard W. Reznicek
EDGAR D. ARONSON BERNARD W. REZNICEK
/s/ Judith E. Ayres /s/ Walter Scott, Jr.
JUDITH E. AYRES WALTER SCOTT, JR.
/s/ Richard K. Davidson /s/ John R. Shiner
RICHARD K. DAVIDSON JOHN R. SHINER
/s/ David H. Dewhurst /s/ Sir Neville G. Trotter
DAVID H. DEWHURST SIR NEVILLE G. TROTTER
/s/ Richard R. Jaros /s/ David E. Wit
RICHARD R. JAROS DAVID E. WIT
/s/ Ben Holt
BEN HOLT
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 1,675,046
<SECURITIES> 1,282
<RECEIVABLES> 376,745
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 0
<PP&E> 4,026,742
<DEPRECIATION> 497,832
<TOTAL-ASSETS> 7,487,626
<CURRENT-LIABILITIES> 0
<BONDS> 3,492,852
553,930
56,181
<COMMON> 5,602
<OTHER-SE> 759,724
<TOTAL-LIABILITY-AND-EQUITY> 7,487,626
<SALES> 2,166,338
<TOTAL-REVENUES> 2,270,911
<CGS> 1,055,195
<TOTAL-COSTS> 345,833
<OTHER-EXPENSES> 52,705
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 251,305
<INCOME-PRETAX> 196,860
<INCOME-TAX> 99,044
<INCOME-CONTINUING> 51,823
<DISCONTINUED> 0
<EXTRAORDINARY> (135,850)
<CHANGES> 0
<NET-INCOME> (84,027)
<EPS-PRIMARY> (1.25)
<EPS-DILUTED> (1.22)
</TABLE>
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
Restated Financial Data Schedule Exhibit 27.2
Item 601(c) of Regulation S-K Commercial
and Industrial Companies Article 5 of Regulation S-X
(dollars in thousands, except per share amounts)
<CAPTION>
Three Months Six Months Nine Months
Ended Ended Ended
December 31, December 31, March 31, June 30, September 30,
Item Number Item Description 1995 1996 1996 1996 1996
<S> <C> <C> <C> <C> <C> <C>
5-02(1) cash and cash items 298,931 579,726 326,150 388,726 465,819
5-02(2) marketable securities 34,190 4,921 12,691 3,295 2,864
5-02(3)(a)(6)notes and accounts
receivable-trade 57,909 342,307 47,527 79,771 109,453
5-02(4) allowances for doubtful
accounts N/A N/A N/A N/A N/A
5-02(6) inventory N/A N/A N/A N/A N/A
5-02(9) total current assets N/A N/A N/A N/A N/A
5-02(13) property, plant and
equipment 1,945,439 3,619,799 2,040,011 2,233,645 2,461,673
5-02(14) accumulated
depreciation 164,184 271,216 179,917 205,021 237,903
5-02(18) total assets 2,654,038 5,712,907 2,721,400 2,975,127 3,548,442
5-02(21) total current liabilities N/A N/A N/A N/A N/A
5-02(22) bonds and
mortgages and
similar debt 1,763,424 2,901,580 1,793,305 1,922,725 2,247,255
5-02(28) preferred stock-
mandatory redemption N/A 103,930 N/A 103,930 103,930
5-02(29) preferred stock-no
mandatory redemption N/A 136,065 N/A N/A N/A
5-02(30) common stock 3,421 4,303 3,523 3,523 3,853
5-02(31) other stockholders'
equity 540,111 876,487 565,705 584,413 717,959
5-02(32) total liabilities and
stockholders'equity 2,654,038 5,712,907 2,721,400 2,975,127 3,548,442
5-03(b)(1)(a)net sales of tangible
products 335,630 518,934 75,944 180,679 346,166
5-03(b)(1) total revenues 398,723 576,195 90,356 206,150 385,198
5-03(b)(2)(a)costs of tangible
goods sold N/A 31,840 N/A N/A N/A
5-03(b)(2) total costs and expenses
applicable to sales and
revenues-operating
expense 103,602 132,655 23,331 51,658 91,840
5-03(b)(3) other costs and
expenses-general
and administration 23,376 21,451 4,179 9,296 15,814
5-03(b)(5) provision for doubtful
accounts and notes N/A N/A N/A N/A N/A
5-03(b)(8) interest and amortization
of debt discount 102,083 126,038 22,873 47,996 85,062
5-03(b)(10) income before taxes
and other items 97,051 135,713 20,958 49,270 108,216
5-03(b)(11) income tax expense 30,631 41,821 6,497 15,537 33,862
5-03(b)(14) income continuing
operations 63,415 92,461 14,461 33,733 71,287
5-03(b)(19) net income 63,415 92,461 14,461 33,733 71,287
5-03(b)(20) earnings per share 1.32 1.69 .28 .65 1.37
5-03(b)(20) earnings per share
diluted 1.22 1.54 .27 .60 1.22
</TABLE>
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
Restated Financial Data Schedule Exhibit 27.3
Item 601(c) of Regulation S-K Commercial
and Industrial Companies Article 5 of Regulation S-X
(dollars in thousands, except per share amounts)
<CAPTION>
Three Months Six Months Nine Months
Ended Ended Ended
March 31, June 30, September 30,
Item Number Item Description 1997 1997 1997
<S> <C> <C> <C> <C>
5-02(1) cash and cash items 457,729 494,953 840,435
5-02(2) marketable securities 6,742 5,958 1,481
5-02(3)(a)(1) notes and accounts
receivable-trade 347,594 343,818 332,991
5-02(4) allowances for doubtful accounts N/A N/A N/A
5-02(6) inventory N/A N/A N/A
5-02(9) total current assets N/A N/A N/A
5-02(13) property plant and equipment 3,913,619 4,055,501 3,963,536
5-02(14) accumulated depreciation 332,179 388,874 445,547
5-02(18) total assets 6,138,050 6,275,061 6,385,039
5-02(21) total current liabilities N/A N/A N/A
5-02(22) bonds and mortgages
and similar debt 3,228,619 3,230,356 3,141,738
5-02(28) preferred stock-mandatory
redemption 283,930 283,930 553,930
5-02(29) preferred stock-no
mandatory redemption 89,040 59,101 56,387
5-02(30) common stock 4,303 4,311 4,312
5-02(31) other stockholders' equity 872,061 913,601 146,062
5-02(32) total liabilities and
stockholders' equity 6,138,050 6,275,061 6,385,039
5-03(b)(1)(a) net sales of tangible
products 542,589 1,048,511 1,576,407
5-03(b)(1) total revenues 565,976 1,090,970 1,642,863
5-03(b)(2)(a) costs of tangible goods sold 277,382 518,930 758,011
5-03(b)(2) total costs and expenses
applicable to sales and
revenues-operating expense 83,611 160,491 243,004
5-03(b)(3) other costs and expenses-
general and administration 13,487 25,492 37,560
5-03(b)(5) provision for doubtful
accounts and notes N/A N/A N/A
5-03(b)(8) interest and amortization
of debt discount 61,500 119,506 182,503
5-03(b)(10) income before taxes and
other items 57,154 117,528 208,675
5-03(b)(11) income tax expense 22,249 46,591 74,520
5-03(b)(14) income continuing operations 27,448 58,337 104,745
5-03(b)(15) discontinued operations N/A N/A N/A
5-03(b)(17) extraordinary items N/A N/A (135,850)
5-03(b)(18) cumulative effect-changes
in accounting principle N/A N/A N/A
5-03(b)(19) net income (loss) 27,448 58,337 (31,105)
5-03(b)(20) earnings per share .43 .92 (.49)
5-03(b)(20) earnings per share diluted .42 .88 (.30)
</TABLE>
