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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
Commission File Number 1-13434
EDISON MISSION ENERGY
(Exact name of registrant as specified in its charter)
CALIFORNIA 95-4031807
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
18101 VON KARMAN AVENUE
IRVINE, CALIFORNIA 92612
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (714) 752-5588
Securities registered pursuant to Section 12(b) of the Act:
9-7/8% CUMULATIVE MONTHLY
INCOME PREFERRED SECURITIES, SERIES A * NEW YORK STOCK EXCHANGE
- --------------------------------------- -----------------------
(Title of Class) (name of each exchange on
which registered)
8-1/2% CUMULATIVE MONTHLY
INCOME PREFERRED SECURITIES, SERIES B * NEW YORK STOCK EXCHANGE
- --------------------------------------- -------------------------
(Title of Class) (name of each exchange on
which registered)
Securities registered pursuant to section 12(g) of the Act:
COMMON STOCK, NO PAR VALUE
--------------------------
(Title of Class)
* Issued by Mission Capital, L.P., a limited partnership in which Edison
Mission Energy is the sole general partner. The payments of distributions on the
preferred securities and payments on liquidation or redemption are guaranteed by
Edison Mission Energy.
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 _____.
Aggregate market value of the registrant's Common Stock held by non-affiliates
of the registrant as of March 27, 1998: $0. Number of shares outstanding of the
registrant's Common Stock as of March 27, 1998: 100 shares (all shares held by
an affiliate of the registrant).
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TABLE OF CONTENTS
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Item Page
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PART I
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1. Business................................................................. 1
2. Properties............................................................... 22
3. Legal Proceedings........................................................ 23
4. Submission of Matters to a Vote of Security Holders...................... 23
PART II
5. Market for Registrant's Common Equity and Related Shareholder Matters.... 24
6. Selected Financial Data.................................................. 25
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................... 26
8. Financial Statements and Supplementary Data.............................. 36
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................... 36
PART III
10. Directors and Executive Officers of the Registrant....................... 69
11. Executive Compensation................................................... 71
12. Security Ownership of Certain Beneficial Owners and Management........... 78
13. Certain Relationships and Related Transactions........................... 80
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.......... 80
Signatures............................................................... 99
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PART I
ITEM 1. BUSINESS
THE COMPANY
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Edison Mission Energy (EME), through its subsidiaries, is engaged in the
business of developing, acquiring, owning and operating electric power
generation facilities worldwide. EME is a wholly owned subsidiary of The Mission
Group, which is a wholly owned, non-utility subsidiary of Edison International.
Edison International is also the parent holding company of Southern California
Edison Company (SCE), one of the largest electric utilities in the United
States.
EME was formed in 1986 with two domestic operating projects. Currently, EME
owns interests in 26 domestic and 24 international operating electrical power
generation facilities with an aggregate generating capacity of 7,403 megawatts
(MW), of which EME's share is approximately 5,173 MW. Three international
projects totaling 1,922 MW of generating capacity (of which EME's anticipated
share is approximately 887 MW) are currently in the construction stage. At
December 31, 1997, the Company had consolidated assets of $5 billion and total
shareholder's equity of $827 million.
EME is incorporated under the laws of the State of California. Its
headquarters and principal executive offices are located at 18101 Von Karman
Avenue, Suite 1700, Irvine, California 92612, and its telephone number is (714)
752-5588. Unless indicated otherwise or the context otherwise requires,
references in this Annual Report on Form 10-K to EME shall be deemed to include
EME, its subsidiaries and the partnerships or limited liability entities through
which EME and its partners own and manage their project investments.
SEGMENT INFORMATION
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EME operates in only one industry segment: electric power generation.
DESCRIPTION OF BUSINESS
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GENERAL OVERVIEW
EME is one of the leading global producers of electricity. Through its
subsidiaries, EME is engaged in the business of developing, acquiring, owning
and operating electric power generation facilities worldwide. EME was formed in
1986 with two domestic operating projects. Currently, EME owns interests in 26
domestic and 24 international operating electrical power generation facilities.
Until the enactment of the Public Utility Regulatory Policies Act of 1978
(PURPA), utilities were the only producers of bulk electric power intended for
sale to third parties in the United States. PURPA encouraged the development of
independent power by removing regulatory constraints relating to the production
and sale of electric energy by certain non-utilities and requiring electric
utilities to buy electricity from certain types of non-utility power producers
(qualifying facilities or QFs) under certain conditions. The passage of the
Energy Policy Act of 1992 (the Energy Policy Act) further encouraged the
development of independent power by significantly expanding the options
available to independent power producers (IPPs) with respect to their regulatory
status and by liberalizing transmission access. As a result, a significant
market for electric power produced by IPPs, such as EME, has developed in the
United States since the enactment of PURPA.
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The movement toward privatization of existing power generation capacity in
many foreign countries and the growing need for new capacity in developing
countries have also led to the development of significant new markets for IPPs
outside the United States. EME believes that it is well-positioned to continue
to realize opportunities in these new foreign markets. See "--Strategy" below.
STRATEGY
EME's business strategy is to play an active role, as a long-term owner, in
all phases of power generation, from planning and development through
construction and commercial operation. EME believes that such involvement
allows EME to better ensure, through the use of its experienced personnel, that
its projects are well-planned, structured and managed.
In making investment decisions, EME evaluates potential project returns
against rate of return guidelines. EME establishes these guidelines by
identifying a base rate of return and adjusting the base rate by potential risk
factors, such as risks associated with project location and stage of project
development. EME endeavors to mitigate project development risk by (i)
selecting partners with complementary skills and local experience, (ii)
structuring investments through subsidiaries, (iii) managing up-front
development costs, (iv) utilizing limited recourse financing and (v) linking
revenue and expense components where appropriate. Many of EME's projects are
operated by its subsidiaries or affiliates (e.g., Edison Mission Operation and
Maintenance, Inc. - Edison Mission O&M), which seek to preserve and enhance the
value of EME's investments.
In response to increasing globalization of the independent power market, EME
has organized its operations and development activities into three geographic
divisions: (i) Americas, (ii) Asia Pacific and (iii) Europe, Central Asia,
Middle East and Africa. Each division is served by one or more teams consisting
of business development, operations, finance and legal personnel, and each team
is responsible for all the activities of EME within a particular geographic
region. Also, EME has mobilized personnel from outside a particular region when
needed in order to assist in the development of certain projects.
Set forth below is a brief discussion of the current strategy for each of the
three regions and a summary of certain of EME's projects that are currently in
the construction, advanced development, pre-finance or early operations stage in
each of the regions. While EME anticipates the successful completion of these
projects, no assurance can be given that any of these projects, or any other
projects currently in the construction stage, advanced development or pre-
finance stage, will be successfully completed or financed or that the expected
MW capacity (and EME's anticipated share thereof) will be achieved. See " --
Project Development -- Certain Considerations Associated with Project
Development, Finance and Operation".
Americas
The Americas division is comprised of the U.S./Canada and Central and Latin
America regions and is headquartered in Irvine, California. The strategy for the
U.S./Canada and Central and Latin America region is to (i) manage certain
operating independent power projects located throughout the United States, (ii)
pursue the acquisition of existing generating assets from utilities, industrial
companies and other IPPs and (iii) pursue the development of new power projects
throughout the region. EME has 26 operating projects in this region. For
further information regarding EME's 26 domestic operating
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projects, see "--EME's Operating Power Generation Facilities-- Description of
Domestic Operating Projects."
Asia Pacific
The Asia Pacific division is headquartered in Singapore with additional
offices located in Australia, Indonesia and the Philippines. Among the three
geographic divisions, the countries covered by the Asia Pacific division have
experienced the fastest electric demand growth, and are expected to continue
strong growth in the medium term. Most governments in the region have committed
to privatization of the electric power industry, and are looking to the private
sector to finance and develop a significant portion of new generating capacity.
The strategy for this region is to (i) pursue projects in countries where
there exist strong political commitment and the structural framework necessary
for private power, (ii) seek opportunities to employ indigenous fuels and (iii)
seek strategic, complimentary alliances with partners who bring value to the
project by providing fuel, equipment and construction services.
EME's activity in the Asia Pacific region commenced in December 1992 with the
acquisition of a 51% interest of the 1000-MW Loy Yang B Power Station (Loy Yang
B) from the State Government of Victoria (State), Australia's first electric
privatization effort. In May 1997, a subsidiary of EME acquired the State's 49%
interest in Loy Yang B. The first of two 500-MW units at Loy Yang B began
commercial operations in October 1993. Unit 2 commenced commercial operations in
October 1996. An EME affiliate provides operation and maintenance services for
both units.
In April 1995, EME and its partners, Mitsui & Co. Ltd., General Electric
Corporation and P.T. Batu Hitam Perkasa, an Indonesian limited liability
company, commenced construction of the $2.5 billion Paiton project, a 1,230-MW
coal-fired power plant in East Java, Indonesia. The project will consist of two
units, each of which is expected to have a capacity of 615 MW. Construction of
the plant continues on schedule, with commercial operation expected in the first
half of 1999. In January 1996, EME purchased an additional 7.5% interest in the
Paiton project from a subsidiary of General Electric Corporation, thereby
increasing its ownership interest to 40%.
Construction on the two-unit Paiton project is approximately 85% complete.
The tariff is higher in the early years and steps down over time, and the tariff
for the Paiton project includes infrastructure to be used in common by other
units at the Paiton complex. The plant's output is fully contracted with the
state-owned electricity company, PT Perusahaan Listrik Negara (PLN), for payment
in U.S. dollars. The projected rate of growth of the Indonesian economy and the
exchange rate of Indonesian Rupiah into U.S. dollars have deteriorated
significantly since the Paiton project was contracted, approved and financed
with substantial finance and insurance support from the Export-Import Bank of
the United States, The Export-Import Bank of Japan, the U.S. Overseas Private
Investment Corporation and the Ministry of International Trade and Industry of
Japan. The Paiton project's senior debt ratings have been reduced from
investment grade to speculative grade based on the rating agencies' perceived
increased risk that PLN might not be able to honor the electricity sales
contract with Paiton. A Presidential decree has deemed some power plants, but
not including the Paiton project, subject to review, postponement or
cancellation.
Kwinana is a $108 million 116-MW gas-fired cogeneration project located at
the British Petroleum Kwinana refinery near Perth, Australia. The project,
which is 100% owned by EME, began commercial operations in December 1996. The
project supplies electricity to Western Power (formerly the State
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Electricity Commission of Western Australia) and electricity and steam to the
British Petroleum Kwinana refinery.
In December 1997, EME (40% ownership), along with its partners, Siam City
Cement (30% ownership) and Lanna Lignite (30% ownership), signed a twenty-five
year power purchase contract with the Electricity Generating Authority of
Thailand (EGAT) pursuant to which EGAT will purchase 734 MW of output from the
coal-fired power generation project at Kui Buri in Thailand. Financial closing
and commencement of construction are anticipated in late 1998 or early 1999 with
commercial operations expected to begin in 2001.
In September 1997, the San Pascual project, a consortium including EME (37.5%
ownership), Texaco Inc. (37.5% ownership) and Caltex (25% ownership), signed a
twenty-five year power purchase contract with the National Power Corporation
(NPC), Philippines' state-owned electric utility company, pursuant to which NPC
will purchase 304 MW of output from the San Pascual project. The low-sulfur
residual fuel oil cogeneration project is located in the Philippines. Financial
closing and commencement of construction are anticipated in 1998 with commercial
operations expected to begin in 2001.
Europe, Central Asia, Middle East and Africa
The European organization is headquartered in London, England with additional
offices located in Italy, Spain and Turkey. The London office was established
in 1989, concurrent with the privatization of the power industry in the United
Kingdom. The territorial scope of the region includes Europe, Africa, the Middle
East, India and Pakistan. The region is characterized by a blend of both mature
and less developed markets. The regional strategy is to pursue the development
and acquisition of medium to large scale power and cogeneration facilities with
diversified fuel sources and generation technology.
EME's operating projects in the region are the First Hydro project located in
North Wales, the Roosecote project in northwest England, the Derwent project
located in Derby, England and the Iberian Hy-Power projects (which consist of 18
small, hydroelectric facilities) in Spain.
EME acquired initial ownership interests of Iberian Hy-Power I and II in
December 1992 and August 1993, respectively. In January 1996, EME purchased the
remaining equity stake in Iberian Hy-Power Amsterdam B.V., increasing its
ownership percentage to approximately 100% (minority interests are owned in
three of the projects by third parties).
In December 1995, EME purchased all of the outstanding shares of First Hydro
Company (First Hydro) for approximately $1 billion (653 million pounds
sterling). First Hydro's principal assets are two pumped-storage electric power
stations located in North Wales at Dinorwig and Ffestiniog, which have a
combined capacity of 2,088 MW. The Dinorwig station, which was commissioned in
1983, is comprised of six units totaling 1,728 MW. The Ffestiniog station was
commissioned in 1963 and is comprised of four units totaling 360 MW. First
Hydro is an independent generating company with three main sources of revenues:
(i) selling power into the electricity trading market or "pool" in England and
Wales, (ii) providing system support services to The National Grid Company plc,
and (iii) selling its installed capacity forward by entering into "contracts for
differences" with large electricity suppliers.
In June 1995, EME (49% ownership) and its partner, ISAB S.p.A. (51%
ownership), signed a twenty-year power purchase contract with ENEL S.p.A.,
Italy's state electricity corporation, pursuant to which ENEL S.p.A. will
purchase 507 MW of output from the 512-MW ISAB power project, which is located
near Siracusa in Sicily, Italy. The project will employ gasification technology
to convert heavy
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oil residues from the ISAB refinery in Priolo Gargallo into clean-burning syngas
that will be used to generate electricity in a combustion turbine. The
approximately 2 trillion lira ($1.3 billion) project financial closing was
completed in April 1996 with construction commencing in July 1996. The project
is more than 75% complete with commercial operation expected in late 1999.
In February 1995, EME (80% ownership) signed a shareholders' agreement to
develop the $180 million Doga Enerji A.S. project in Esenyurt, near Istanbul,
Turkey. The 180-MW combined cycle gas-fired cogeneration facility is
approximately 63% complete with commercial operations expected in 1999. In
April 1997, EME completed financing and commenced construction of the Doga
project.
PROJECT DEVELOPMENT
The development of power generation projects involves numerous elements,
including evaluating and selecting development opportunities, evaluating market
risk, designing and engineering the project, acquiring necessary land rights,
permits and fuel resources, obtaining financing and managing construction and,
in some cases obtaining power sales agreements and steam sales agreements.
EME initially evaluates and selects potential development projects based on a
variety of factors, including whether a project is based on a proven technology,
the strength of the potential partners in the project, the feasibility of the
project, the likelihood of obtaining a power sales agreement, the probability of
obtaining required licenses and permits and the projected economic return from
the project. During the development process, EME monitors the viability of the
project and makes business judgments concerning expenditures for both internal
and external development costs. Completion of the financing arrangements for a
project is generally an indication that business development activities are
substantially complete.
Although EME has in the past been successful in developing projects with
long-term contracts and arranging for necessary permits and approvals, there can
be no assurance that EME will continue to be successful in doing so in the
future. EME believes that future market conditions for independent power,
particularly in the United States, may become increasingly characterized by
shorter-term power sales agreements or spot sales arrangements. EME may be
required to consider market or "merchant" risk in the future.
Project Type
The selection of power generation technology for a particular project is
influenced by various factors, including regulatory requirements, availability
of fuel and anticipated economic advantages for a particular application. The
principal technology used in EME's operating projects has been gas-fired
combustion turbine technology, predominately through an application known as
"cogeneration". Cogeneration facilities sequentially produce two or more useful
forms of energy (e.g., electricity and steam) from a single primary source of
fuel (e.g., natural gas or coal). Many of EME's cogeneration projects are
located near large industrial steam users or in oil fields that inject steam
underground to enhance recovery of heavy oil. The regulatory advantages for
cogeneration facilities under PURPA have become less significant because of
expanded project options made available to IPPs under the Energy Policy Act.
Accordingly, although cogeneration may provide a competitive advantage in the
new market place, EME expects that the majority of its future projects will
generate power without selling steam to industrial users.
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EME also has interests in projects that use renewable resources such as
hydroelectric and geothermal energy. EME's hydroelectric projects, excluding
First Hydro, use "run-of-the-river" technology to generate electricity. The
First Hydro project utilizes pumped-storage stations which consume electricity
when it is comparatively less expensive in order to pump water up for storage in
an upper reservoir. Water is then allowed to flow back through turbines in
order to generate electricity when its market value is higher. This type of
generation is characterized by its speed of response, its ability to work
efficiently at wide variations of load and the basic reliance of revenue on the
difference between the peak and trough prices of electricity during the day.
EME's geothermal projects use technologies that convert the heat from geothermal
fluids and underground steam into electricity.
EME has international interests in an operating project and projects under
construction and advanced development which are large scale, coal-fired projects
using pulverized coal in coal-fired generation technology. In the United
States, EME has developed coal and waste coal-fired projects that employ
traditional stoker and circulating fluidized bed technology.
Power and Steam Sales Contracts
Electric power and steam generated by EME's operating projects in the U.S. is
sold primarily to domestic electric utilities and industrial steam users
pursuant to long-term (typically, 15 to 30 year) contracts. Excluding the U.K.
and a project in Australia, electric power generated overseas is sold primarily
under long-term contracts to electric utilities located in the country where the
power is generated. A project's revenue from a power sales contract usually
consists of two components: energy payments and capacity payments. Energy
payments are generally based on actual deliveries of electric energy (e.g.,
kilowatt-hours) to the purchasing utility. Energy payment rates are usually
indexed to certain variable costs that the purchasing utility avoids by
purchasing such electric energy directly as opposed to operating its own power
plant(s) to produce the same amount of electric energy. The variable components
typically include the fuel cost and certain operation and maintenance expenses.
These costs may be indexed to the utility's cost of fuel and/or certain
inflation indices. Energy payments may also be time-differentiated to provide
relatively higher payments for electric energy delivered during periods of peak
electricity demand. Capacity payments are generally based on a project's proven
capability to deliver reliable electric energy, whether or not the plant is
called on to operate. Capacity payment rates are usually associated with certain
fixed costs that the purchasing utility avoids by having the independent power
producer build and maintain the availability of a power plant. To receive
capacity payments, there are typically minimum performance standards that must
be met and often there is a performance range that further influences the amount
of capacity payments.
EME's power sales contracts are typically negotiated during the planning
stage of a project. In negotiating the power sales contracts, EME attempts to
secure long-term contracts that are expected to result in consistent cash flow
under a wide range of economic and operating circumstances. To accomplish this,
EME structures the revenue provisions of the power sales contract so that
changes in the cost components of a facility (e.g., fuel costs) will correspond
to, as effectively as possible, similar changes in the revenue components of the
contract.
In addition to entering into a power sales agreement, EME must make
arrangements to interconnect its project to a local utility's electric system.
The arrangement is typically evidenced through an interconnection agreement that
sets forth the provisions for construction, payment and technical requirements
for the interconnection facilities. In some cases, the project will interconnect
with a utility system that is not the ultimate purchaser of electric power. In
such circumstances, the project must arrange for the local utility to transmit
or "wheel" its power to the ultimate purchaser.
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Projects in the U.K. and a project in Australia sell their electrical energy
and capacity through a centralized electricity pool, which establishes a half-
hourly clearing price (also referred to as the "pool price"). The pool price is
extremely volatile and in the U.K. can vary by as much as a factor of ten or
more over the course of a few hours, due to the large differentials in demand
according to the time of day. First Hydro mitigates a significant portion of the
market risk of the pool by entering into contracts for differences (electricity
rate swap agreements), related to either the selling or purchasing price of
power, whereby a contract specifies a price at which the electricity will be
traded, and the parties to the agreement make payments, calculated based on the
difference between the price in the contract and the pool price for the element
of power under contract. These contracts can be sold in two structures: one-way
contracts, where a specified monthly amount is received in advance and
difference payments are made when the pool price is above the price specified in
the contract, and two-way contracts, where the counterparty pays First Hydro
when the pool price is below that in the contract instead of a specified monthly
amount. These contracts act as a means of stabilizing production revenues or
purchasing costs by removing an element of First Hydro's net exposure to pool
price volatility. The Roosecote project has avoided the pool price volatility by
entering into a long-term power sales contract that provides for contract
pricing. The Roosecote project's power sales contract provides for the
escalation of capacity payments according to an inflation index for the U.K.
Loy Yang B has entered into a number of financial hedges to mitigate exposure
to price volatility of the electricity traded into the pool. From May 8, 1997
to December 31, 2000, approximately 53% to 64% of the plant output sold is
hedged under "Vesting Contracts" with the remainder of the plant capacity hedged
under the "State Hedge" described below. Vesting Contracts were put into place
by the State, between each generator and each distributor, prior to the
privatization of electric power distributors in order to provide more
predictable pricing for those electricity customers that were unable to choose
their electricity retailer. Vesting Contracts set base strike prices at which
the electricity will be traded, and the parties to the agreement make payments,
calculated based on the difference between the price in the contract and the
half-hourly pool clearing price for the element of power under contract. These
contracts can be sold as one-way or two-way contracts which are structured
similar to the electricity rate swap agreements described above. These
contracts are accounted for as electricity rate swap agreements. The State
Hedge is a long-term contractual arrangement based upon a fixed price commencing
May 8, 1997 and terminating October 31, 2016. The State guarantees SECV's
obligations under the State Hedge.
Steam produced from EME's cogeneration facilities is sold to industrial steam
users, such as petroleum refineries or companies involved in the enhanced
recovery of oil through steam flooding of oil fields, under long-term steam
sales contracts. Domestic steam sales contracts require the purchaser to take
at least the minimum amount of steam necessary for the project to retain its QF
status under PURPA.
Steam payments are generally based on formulas that reflect the cost of
water, fuel and capital. In some cases, EME has provided steam purchasers with
discounts from their previous cost for producing such steam and/or partially
indexed steam payments to other indices including certain oil prices.
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Fuel Supply Contracts
EME seeks to enter into long-term fuel supply and transportation agreements.
Market prices for oil, gas and coal historically have fluctuated significantly.
EME believes, however, that its financial condition will not be substantially
adversely affected by such fluctuations because its long-term contracts to sell
power and steam typically are structured so that fluctuations in fuel costs will
produce similar fluctuations in electric energy and/or steam revenues. The
degree of linkage between such revenues and expenses varies from project to
project, but generally permits the projects to operate profitably under a wide
array of potential price fluctuation scenarios.
Project Financing
Each power generation project developed by EME requires a substantial capital
investment. The permanent project financing for a project is often arranged
immediately prior to the construction of the project. With limited exceptions,
such debt financing is for approximately 60 to 80% of each project's costs and
is expected to be structured, on a basis that is nonrecourse to EME and its
other projects. In addition, the collateral security for each project's
financing generally has been limited to the physical assets, contracts and cash
flow of that project.
In general, each of EME's direct or indirect subsidiaries is organized as a
legal entity separate and apart from EME and its other subsidiaries. Any asset
of any such subsidiary may not be available to satisfy the obligations of EME 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 EME or its
affiliates.
The ability to arrange for financing and the cost of such financing are
dependent upon numerous factors, including general economic and capital market
conditions, conditions in energy markets, regulatory developments, credit
availability from banks or other lenders, investor confidence in the industry,
EME and other project participants, the continued success of EME's current
projects, and provisions of tax and securities laws that are conducive to
raising capital.
To obtain project financing, EME and its partners are sometimes required to
provide certain guarantees and warranties to lenders, particularly with respect
to construction financing. However, because permanent financing is usually
arranged on a nonrecourse basis, EME's liability is generally substantially
reduced when construction has been completed and the project has passed all
acceptance tests. EME's financial exposure in any project is generally limited
by contractual arrangement to its equity commitment, which is usually about 20
to 40% of EME's share of the aggregate project cost. In addition, the project
loan agreements are generally structured so that a default under one project
loan agreement will have no effect on the loan agreements of other EME projects.
Permits and Approvals
Because the process for obtaining initial environmental, siting and other
governmental permits and approvals is complicated and lengthy (often taking a
year or longer), EME seeks to obtain all permits, licenses and other approvals
required for the construction and operation of the project, including siting,
construction and environmental permits, rights-of-way and planning approvals,
early in the development process. See "Certain Regulatory Matters-- General".
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Construction and Implementation
In the project implementation stage, EME provides project and construction
management and start-up and testing services. The detailed engineering and
construction of the projects typically are done by outside contractors under
fixed-price, "turnkey" contracts. Under such contracts, the contractor
generally is required to pay liquidated damages to EME in the event of cost
overruns or schedule delays or if the facility fails to meet certain capacity,
efficiency and emission standards.
As a project goes into operation, operation and maintenance services are
provided to the project by one of EME's operation and maintenance subsidiaries
or another operation and maintenance contractor. The day-to-day operation of
each project is generally managed by an executive director. Management
committees comprised of the project partners generally meet monthly or quarterly
to review and manage the operating performance of each project.
Certain Considerations Associated with Project Development, Finance and
Operation
Independent power projects are necessarily subject to a variety of
commercial, financial and other risks, including those described below. By
managing, or participating in the management of each project in which it
invests, EME seeks to hedge, insure against or otherwise manage these risks.
EME attempts to minimize the financial risk in the development of a project
by securing a favorable long-term power sales agreement, obtaining all required
governmental permits and approvals and arranging adequate financing prior to the
commencement of construction. However, the development of a power project may
require EME to expend significant sums for preliminary engineering, permitting
and legal and other expenses before it can determine whether a project is
feasible, economically attractive or financeable. Power sales agreements often
enable the utility to terminate such agreement, or to retain security posted by
the developer as liquidated damages, in the event that a project fails to
achieve commercial operation or certain operating levels by specified dates or
fails to meet other significant contractual requirements. Furthermore, utility
regulators or other parties may attempt to abrogate or amend contracts under
which a project is entitled to receive material revenues or other benefits. If
such events were to occur, the default provisions in a financing agreement could
be triggered (rendering such project debt immediately due and payable) and, as a
result, EME could lose its interest in the project. Although contractual and
regulatory risks cannot be eliminated, EME believes that it has relevant
experience in developing contracts and mitigating regulatory concerns.
Certain geographic areas in which EME operates and is developing projects are
subject to frequent earthquakes of low intensity, and earthquakes of greater
intensity are possible. EME's existing power generation facilities are built to
withstand earthquakes of relatively significant intensity and EME believes it
maintains adequate insurance protection for such occurrences and other
catastrophic events.
The operation of a project involves many risks, including start-up problems,
the breakdown or failure of equipment or processes, performance below expected
levels of output and the inability to meet expected efficiency standards. EME
takes steps to mitigate these risks by obtaining equipment and plant warranties
and arranging for insurance that it believes is adequate. Nonetheless, these
measures may not be adequate to cover lost revenues or increased expenses and,
as a result, a project may be unable to fund principal and interest payments
under its financing obligations and may operate at a loss. A default under such
a financing obligation could result in EME losing its interest in such power
generation facility.
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EME believes, however, that it will continue to maintain a successful record of
plant performance and operation.
EME's operations are conducted through its subsidiaries and EME's cash flow
is dependent upon the operating revenues of its subsidiaries and the ability of
those subsidiaries to pay cash dividends or make distributions to EME. Financing
agreements for EME's subsidiaries and affiliates generally place certain
limitations on the ability of those subsidiaries and affiliates to pay
dividends, make distributions or otherwise transfer funds to EME. In addition,
financing agreements for EME's subsidiaries and affiliates, although generally
nonrecourse to EME, contain certain representations, warranties, covenants and
other agreements that, if not met, could lead to a default under such financing.
After a default under a project financing for any reason, project lenders may
exercise certain rights and remedies typically granted to secured parties,
including the ability to take control of the project's collateral assets.
The financing and development of international projects entail additional
political and financial risks including uncertainties associated with
privatization efforts, currency exchange rates, currency repatriation, political
instability and other issues that have the potential to cause delays or
impairment of value to the project being developed for which EME may not be
fully capable of insuring against. The uncertainty of the legal structure in
certain foreign countries in which EME may develop or acquire projects could
make it more difficult to enforce its rights under agreements relating to such
projects. In addition, the laws and regulations of certain countries may limit
the ability of EME to hold a majority interest in some of the projects that it
may develop or acquire. Although the risks of participation in international
markets are significant, EME targets relatively higher rates of return on its
international investments and mitigates risk by seeking complimentary alliances
with well-established partners and hedging foreign exchange exposure where it
deems appropriate.
OPERATION AND MAINTENANCE SERVICES
Certain EME subsidiaries provide specialized operating, maintenance, testing
and start-up services for EME-owned projects. At December 31, 1997, Edison
Mission O&M or other subsidiaries had a total of 877 employees and operated 37
of EME's projects totaling 5,161 MW of capacity.
The projects that EME operates have achieved an average 97% availability
during 1997. Availability is a measure of the weighted average number of hours
each generator is available for generation as a percentage of the total number
of hours in a year.
EME'S OPERATING POWER GENERATION FACILITIES
Domestic Overview
EME currently owns interests in 26 domestic operating projects in eight
states. These operating projects consist of 16 natural gas cogeneration
projects, one coal cogeneration project, one waste coal project, four geothermal
projects and four gas-fired EWG (as defined herein) projects. All of EME's
domestic cogeneration and geothermal projects, as well as the waste coal
project, are qualifying facilities under PURPA. EME's domestic operating
projects have total generating capacity of 3,679 MW, of which EME's net
ownership share is 1,640 MW.
Each of EME's projects generally relies on one power sales contract with a
single electric utility customer for the majority, and in some cases all, of its
power sales revenues over the life of the power sales contract. The primary
power sales contracts for seven of EME's operating projects are with SCE.
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EME's share of revenues from these projects accounted for 12% of EME's
consolidated revenues in 1997 and 1996. The failure of SCE to fulfill its
contractual obligations could have a negative impact on a source of EME's
revenues. Under the terms of an agreement between SCE and the Office of
Ratepayer Advocates (ORA), the consumer advocacy branch of the California Public
Utility Commission (CPUC), SCE is prohibited from entering into future power
sales contracts with EME or its affiliates without ORA and CPUC consent. The
terms of the agreement, however, do not affect the terms of the existing power
sales contracts between EME and SCE. Fuel supply for EME's projects generally is
arranged through third-party suppliers and transporters.
EME's geothermal projects have power sales agreements that provide for energy
payments that escalate at predetermined rates during the first 10 years of plant
operation. After the initial 10-year period, the energy payments will be based
on rates published monthly by the purchasing utility that reflect its cost for
natural gas and/or oil. Based on current forecasts of natural gas and oil
prices, EME expects the energy payment rate to drop substantially after the
initial 10-year period. Accordingly, cash distributions received from these
projects are recorded as reductions in the equity investments. Future cash
distributions are estimated to be sufficient to recover the remaining geothermal
investment balances. In April 1996, CalEnergy Company, Inc., EME's partner in
four operating geothermal projects in California, purchased all of the stock of
four wholly owned subsidiaries of EME, which held 50% interests in these
projects. The purchase price of $70 million resulted in a pre-tax gain of $20
million. There will be no impact on EME's future revenues as EME discontinued
recognizing earnings from these projects during 1993.
In January 1998, Oxbow Power of Beowawe, Inc., EME's partner in an operating
geothermal project in Nevada, purchased EME's 50% general partnership interest
in this project from a wholly owned subsidiary of EME. The purchase price of
$4.1 million resulted in an after tax gain of $1.1 million. There will be no
impact on EME's future revenues as EME discontinued recognizing earnings from
this project in 1996.
In February 1998, the CPUC issued an order which approved an agreement
entered into in August 1997 between an operating geothermal project in
California in which EME has a 50% partnership interest and SCE to terminate two
power sales agreements. There will be no negative impact on EME's future
revenues as EME discontinued recognizing earnings from this project during 1993.
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Description of Domestic Operating Projects
EME has ownership interests in the following domestic operating projects:
<TABLE>
<CAPTION>
ELECTRIC PRIMARY OPERATION/
CAPACITY ELECTRIC TYPE OF OWNERSHIP ACQUISITION
PROJECT LOCATION (IN MW) PURCHASER(3) FACILITY(4) INTEREST DATE
- ------- -------- ------- ------------ ----------- -------- -----------
<S> <C> <C> <C> <C> <C> <C>
Aidlin(1) Cloverdale, California 20 PG&E Geothermal 5% 1990
American Bituminous(2) Grant Town, West Virginia 80 MPC Waste Coal 50% 1993
Auburndale(2) Polk County, Florida 150 FPC EWG 50% 1994
Bayonne Bayonne, New Jersey 165 JCP&L/PSE&G Cogeneration 0.38% 1989
Brooklyn Navy Yard Brooklyn, New York 286 CE Cogeneration 50% 1996
Coalinga(2) Coalinga, California 38 PG&E Cogeneration 50% 1991
Commonwealth Atlantic Chesapeake, Virginia 340 VEPCO EWG 50% 1992
GEO East Mesa(1,2) Holtville, California 40 SCE Geothermal 50% 1989
Gordonsville(2) Gordonsville, Virginia 240 VEPCO EWG 50% 1994
Harbor(2) Wilmington, California 80 SCE Cogeneration 30% 1989
Hopewell Hopewell, Virginia 356 VEPCO Cogeneration 25% 1990
James River Hopewell, Virginia 110 VEPCO Cogeneration 50% 1987
Kern River(2) Oildale, California 300 SCE Cogeneration 50% 1985
Lost Hills Lost Hills, California 10 PG&E Cogeneration 50.09% 1989
March Point 1 Anacortes, Washington 80 PSE Cogeneration 50% 1991
March Point 2 Anacortes, Washington 60 PSE Cogeneration 50% 1993
Mid-Set(2) Fellows, California 38 PG&E Cogeneration 50% 1989
Midway-Sunset(2) Fellows, California 225 SCE Cogeneration 50% 1989
Nevada Sun-Peak Las Vegas, Nevada 210 NVP EWG 50% 1991
Saguaro(2) Henderson, Nevada 90 NVP Cogeneration 50% 1991
Salinas River(2) San Ardo, California 38 PG&E Cogeneration 50% 1991
Sargent Canyon(2) San Ardo, California 38 PG&E Cogeneration 50% 1991
Sycamore(2) Oildale, California 300 SCE Cogeneration 50% 1988
Watson Carson, California 385 SCE Cogeneration 49% 1988
</TABLE>
(1) Consists of two projects on the same site.
(2) Operated by EME.
(3) Electric purchaser abbreviations are as follows:
<TABLE>
<C> <S> <C> <C>
CE Consolidated Edison Company of New York, Inc. PG&E Pacific Gas & Electric Company
FPC Florida Power Corporation PSE Puget Sound Energy
JCP&L Jersey Central Power & Light Company PSE&G Public Service Electric & Gas Company
MPC Monongahela Power Company SCE Southern California Edison Company
NVP Nevada Power Company VEPCO Virginia Electric & Power Company
</TABLE>
(4) All of the cogeneration projects are gas-fired facilities, except for the
James River project, which uses coal.
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International Overview
EME owns interests in 24 operating projects outside the United States. The
total generating capacity of such facilities is 3,724 MW, of which EME's net
ownership share is 3,533 MW.
Description of International Operating Projects
EME has ownership interests in the following international operating projects:
<TABLE>
<CAPTION>
ELECTRIC OPERATION/
CAPACITY PRIMARY ELECTRIC OWNERSHIP ACQUISITION
PROJECT LOCATION (IN MW) PURCHASER(2) INTEREST DATE
- ------- -------- ------- ------------ --------- ----------
<S> <C> <C> <C> <C> <C>
Alos(1) Spain 5 FECSA 100% 1993
Bocos(1) Spain 2 FECSA 100% 1993
Castellas(1) Spain 2 FECSA 100% 1993
Derwent(1) England 214 SE(3) 33% 1995
Dinorwig(1) Wales 1,728 Pool 100% 1995
Ffestiniog(1) Wales 360 Pool 100% 1995
Gelsa(1) Spain 7 FECSA 100% 1993
Kwinana(1) Australia 116 WP 100% 1996
La Flecha(1) Spain 3 FECSA 100% 1993
La Ribera(1) Spain 4 FECSA 100% 1993
Logrono(1) Spain 4 FECSA 100% 1993
Loy Yang B(1) Australia 1,000 Pool(4) 100% 1993, 1996,
1997
Mendavia(1) Spain 6 FECSA 100% 1993
Menuza(1) Spain 17 FECSA 91.3% 1992
Monasterio(1) Spain 2 FECSA 100% 1993
Olvera(1) Spain 2 FECSA 100% 1992
Quintana(1) Spain 1 FECSA 100% 1993
Roosecote England 220 NORWEB(5) 80% 1992
Sardon Bajo(1) Spain 2 FECSA 100% 1993
Sastago I(1) Spain 3 FECSA 91.3% 1992
Sastago II(1) Spain 17 FECSA 91.3% 1992
Sossis(1) Spain 4 FECSA 100% 1992
Toro(1) Spain 4 FECSA 100% 1993
Tudela(1) Spain 1 FECSA 100% 1993
</TABLE>
(1) Operated by EME.
(2) Electric purchaser abbreviations are as follows:
<TABLE>
<C> <S> <C> <C>
FECSA Fuerzas Electricas de Cataluma, S.A. Pool Electricity trading market for England,
NORWEB North Western Electricity Board Wales and Australia
WP Western Power SE Southern Electric plc.
</TABLE>
(3) Sells to the pool with a long-term contract with SE.
(4) Sells to the pool with a long-term contract with the State Electricity
Commission of Victoria.
(5) Sells to the pool with a long-term contract with NORWEB.
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OIL AND GAS INVESTMENTS
In 1988, EME formed a wholly owned subsidiary, Mission Energy Fuel Company,
to develop and invest in fuel interests. Since that time, EME has invested in a
number of oil and gas properties and a production company. Oil and gas produced
from the properties are generally sold at spot or short-term market prices.
Four Star
As of December 31, 1997, EME owned 46.85% of the stock of Four Star Oil & Gas
Company (Four Star), a subsidiary of Texaco Inc. The underlying value of Four
Star is attributable to production of oil and gas from nine producing
properties. EME's proportionate interest in net quantities of proved reserves
at December 31, 1997 totaled 189 billion cubic feet of natural gas and 21.6
million barrels of oil.
During 1995, EME and/or Four Star entered into a series of transactions which
resulted in a net increase in EME's ownership of Four Star by 2.47%. During
1996, EME purchased additional shares of stock of Four Star increasing its
ownership by 4.38%. In January 1998, EME purchased additional shares of stock
of Four Star for approximately $4 million increasing its ownership by 3.24% to
50.09% and its voting ownership to 48.97%.
B.C. Star
B.C. Star was formed in 1991 when a subsidiary of EME and a subsidiary of
Texaco Inc. each purchased a 50% partnership interest in certain proved
producing properties from Esso Resources Canada Limited. These properties are
geographically concentrated in the northeast region of British Columbia and
enjoy proximity and direct pipeline access to the Pacific Northwest and
California. Texaco Canada Petroleum Inc. operates the majority of B.C. Star's
properties.
During the second quarter of 1997, EME completed a sale of its ownership
interest in B.C. Star for approximately $71 million. EME recorded an after-tax
gain of approximately $14 million on the sale.
COMPETITION
EME competes with many other companies, including multinational development
groups, equipment suppliers and other IPPs (including affiliates of utilities),
in selling electric power and steam, and with electric utilities in obtaining
the right to install new generating capacity. Over the past decade, obtaining a
power sales contract with a utility has generally become a progressively more
difficult, expensive and competitive process. Many power sales contracts are now
awarded by competitive bidding, which both increases the costs of obtaining such
contracts and decreases the chances of obtaining such contracts. As a result of
competition, it may be difficult to obtain a power sales agreement for a
proposed project, and the prices offered in new power sales agreements for both
electric capacity and energy may be less than the prices in prior agreements.
EME evaluates each potential project in an effort to determine when the
probability of success is high enough to justify expenditures in developing a
proposal or bid for the project.
Amendments to the Public Utility Holding Company Act of 1935 (PUHCA) made by
the Energy Policy Act have increased the number of competitors in the domestic
independent power industry by
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reducing certain restrictions applicable to projects that are not QFs under
PURPA. "Retail wheeling" of power could also lead to increased competition in
the independent power market. See "Certain Regulatory Matters--Retail
Competition".
TAX SHARING AGREEMENTS
EME is included in the consolidated federal income tax and state franchise
tax returns of Edison International. EME calculates its current tax benefit
receivable on a separate company basis under a tax sharing agreement with The
Mission Group, which in turn has a tax sharing agreement with Edison
International. The Mission Group receives payment from Edison International for
tax benefits and pays Edison International for tax liabilities. The Mission
Group similarly pays EME for tax benefits and EME pays The Mission Group for tax
liabilities.
EMPLOYEES AND OFFICES
At February 27, 1998, EME employed 1,172 people, all of whom were full-time
employees and approximately 216, 26 and 144 of whom were covered by a collective
bargaining agreement in Wales, Spain and Australia, respectively. EME has never
experienced a work stoppage, strike or labor dispute. EME believes its relations
with its employees to be good.
EME leases its corporate headquarters in Irvine, California and its principal
regional offices in London, Melbourne and Singapore. It also leases other
smaller offices in the United States and certain foreign countries.
CERTAIN REGULATORY MATTERS
- --------------------------
GENERAL
EME's domestic projects are subject to energy, environmental and other
governmental laws and regulations at the federal, state and local levels in
connection with the development, ownership and operation of its projects.
Federal laws and regulations govern, among other things, transactions by and
with utility companies, the operations of a project and the ownership of a
project. Under certain circumstances where exclusive federal jurisdiction is not
applicable or specific exemptions are otherwise unavailable, state utility
regulatory commissions may have broad jurisdiction over non-utility owned
electric power plants. Energy-producing projects are also subject to federal,
state and local laws and regulations that govern the geographical location,
zoning, land use and operation of a project. Federal, state and local
environmental requirements generally require that a wide variety of permits and
other approvals be obtained before the commencement of construction or operation
of an energy-producing facility and that the facility then operate in compliance
with such permits and approvals. While EME believes the requisite approvals for
its existing projects have been obtained and that its business is operated in
substantial compliance with applicable laws, EME remains subject to a varied and
complex body of laws and regulations that both public officials and private
parties may seek to enforce. There can be no assurance that future developments
will not have a material adverse effect on EME's business or results of
operations, nor can there be any assurance that EME will be able to obtain and
comply with all necessary licenses, permits and approvals for proposed projects.
In addition, regulatory compliance for the construction of new facilities is a
costly and time consuming process. Intricate and changing environmental and
other regulatory requirements may necessitate substantial expenditures and may
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<PAGE>
create a significant risk of expensive delays or significant loss of value in a
project if the project is unable to function as planned due to changing
requirements or local opposition.
Each of EME's international projects will be (or, to the extent that such
projects are already in operation or under construction, currently are) subject
to the energy and environmental laws and regulations of the foreign jurisdiction
in which it is located. The degree of regulation will vary according to each
country and may be materially different from the regulatory regime in the United
States.
U.S. FEDERAL ENERGY REGULATION
The enactment of PURPA in 1978 and the adoption of regulations thereunder by
the Federal Energy Regulatory Commission (FERC) provided incentives for the
development of cogeneration facilities and small power production facilities
(those utilizing alternative or renewable fuels). The passage of the Energy
Policy Act in 1992 further encouraged independent power production by providing
certain exemptions from PUHCA (but not from the Federal Power Act (FPA) or state
regulation) for exempt wholesale generators (EWGs) and foreign utility companies
(FUCOs).
A domestic electricity generating project must be a QF under FERC regulations
in order to take advantage of certain rate and regulatory incentives provided by
PURPA. Subject to certain exceptions, PURPA exempts owners of QFs from PUHCA,
exempts QFs from most provisions of the FPA and, except under certain limited
circumstances, state laws concerning rate or financial regulation. In order to
be a QF, a cogeneration facility must (i) sequentially produce both useful
thermal (e.g., steam) and electric energy, (ii) meet certain operating standards
and energy efficiency standards when oil or natural gas is used as a fuel source
and (iii) not be controlled, or more than 50% owned by, an electric utility,
electric utility holding company or an affiliate thereof. A non-cogeneration
facility may also be a QF if it produces power from renewable energy (e.g.,
geothermal energy) or a waste source of fuel (e.g., waste coal). Before 1990,
non-cogeneration QFs were subject to 30-MW or 80-MW size limits, depending upon
their fuel source. In 1990, these limits were lifted for solar, wind, waste, and
geothermal QFs, provided that applications for or notices of QF status were
filed with FERC for such facilities on or before December 31, 1994, and
provided, in the case of new facilities, the construction of such facilities
commenced on or before December 31, 1999.
Amendments made to PUHCA by the Energy Policy Act provide that owners or
operators of EWGs and FUCOs will not be considered "electric utility companies"
under PUHCA. An EWG is an entity determined by the FERC to be exclusively
engaged, directly or indirectly, in the business of owning and/or operating
certain eligible facilities and selling electric energy at wholesale (or, if
located in a foreign country, at wholesale or retail). A FUCO is, in general, an
entity located outside the United States that owns or operates facilities used
for the generation, distribution or transmission of electric energy for sale or
the distribution at retail of natural or manufactured gas, but derives none of
its income, directly or indirectly, from such activities within the United
States.
The exemptions from federal and state regulation afforded to QFs, and the
exemptions from PUHCA afforded to EWGs and FUCOs, are important to EME and to
its competitors. Under present federal law, EME is not and will not be subject
to regulation as a holding company under PUHCA as long as the projects in which
it has an interest are QFs, EWGs or FUCOs (or are subject to another exemption
from regulation). Of the projects that EME currently owns, operates or has an
investment in, 22 projects have been certified as QFs by the FERC, four projects
have been certified as EWGs and 15 projects are FUCOs. Most of the U.S. projects
currently in the planning or development stage are expected to be QFs and the
international projects are expected to be FUCOs. To the extent that any of
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EME's projects in the development stage will not be QFs or FUCOs, EME expects to
qualify those projects as EWGs. See "PUHCA".
PURPA
PURPA provides two primary benefits to QFs. First, QFs are relieved of
compliance with extensive federal and state regulations that control the
development, financial structure and operation of an energy-producing project
and the prices and terms on which wholesale energy may be sold by the project.
Second, FERC regulations promulgated under PURPA require that electric utilities
purchase electricity generated by QFs at a price based on the purchasing
utility's "avoided cost," and that the utilities sell back-up power to the QF on
a non-discriminatory basis. The term "avoided cost" is defined by PURPA as the
"incremental cost to an electric utility of electric energy or capacity or both
which, but for the purchase from the qualifying facility or qualifying
facilities, such utility would generate itself or purchase from another source."
FERC regulations also permit QFs and utilities to negotiate agreements for
utility purchases of power at prices lower than the utility's avoided costs.
While public utilities are not explicitly required by PURPA to enter into long-
term contracts, it has been common for long-term contracts to be negotiated in
order, among other things, to facilitate project financing of independent power
facilities and to reflect the deferral by the utility of capital costs for new
plant additions. However, increasing competition and power brokering may result
in a trend toward shorter term power contracts that would place greater risk on
the project owner.
EME endeavors to develop its QF projects, monitor regulatory compliance by
such projects and choose its customers in a manner that minimizes the risks of
losing such projects' QF status. However, certain factors necessary to maintain
QF status are subject to the risk of events outside EME's control. For example,
loss of a thermal energy customer or failure of a thermal energy customer to
take required amounts of thermal energy from a cogeneration facility that is a
QF could cause the facility to fail requirements regarding the level of useful
thermal energy output. Upon the occurrence of such an event, EME would seek to
replace the thermal energy customer or find another use for the thermal energy
that meets PURPA's requirements, but no assurance can be given that this would
be possible.
If one of the projects in which EME has an interest was to lose its status as
a QF, the project would no longer be entitled to the QF-related exemptions from
regulation under PUHCA and the FPA. This could subject the project to rate
regulation as a public utility under the FPA and could result in EME
inadvertently becoming a public utility holding company by owning more than 10%
of the voting securities of, or controlling, a facility that would no longer be
exempt from PUHCA. Loss of QF status may also trigger defaults under covenants
to maintain QF status in the project's power sales agreements, steam sales
agreements and financing agreements and result in termination, penalties or
acceleration of indebtedness under such agreements. Such loss of QF status may
be on a retroactive or a prospective basis. If a power purchaser ceased taking
and paying for electricity or sought to obtain refunds of past amounts paid due
to the loss of QF status, there can be no assurance that the costs incurred in
connection with the project could be recovered through sales to other
purchasers. Moreover, EME's business and financial condition could be adversely
affected if regulations or legislation were modified or enacted that changed the
standards for achieving QF status or that eliminated or reduced the benefits
currently enjoyed by QFs. If a project were to lose its QF status, EME could
attempt to avoid holding company status on a prospective basis by qualifying the
project as an EWG. However, assuming this changed status would be permissible
under the terms of the applicable power sales agreement, rate approval from the
FERC would be required. In addition, the project would be required to cease
selling electricity to any retail customers (in order to qualify for EWG status)
and could become subject to state regulation of sales of thermal energy. Loss of
QF status on a retroactive basis could lead to, among other things, fines
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and penalties being levied against EME and its subsidiaries, or claims by the
utility customer for refund of payments previously made. Loss of QF status by
one project could also, because of PURPA ownership restrictions, adversely
affect the QF status of other projects having one or more of the same partners.
In addition, pursuant to Section 26(b) of PUHCA, any project contracts that are
entered into in violation of PUHCA are subject to possible voidability by the
courts should a lawsuit to void the contract be filed.
The Energy Policy Act
The passage of the Energy Policy Act in 1992 significantly expanded the
options available to IPPs with respect to their regulatory status. The Energy
Policy Act created a new class of power producer, the EWG, that (like a QF) is
not considered an electric utility company under PUHCA. EWGs may own facilities
of any size, use any fuel source and may be owned by utilities or non-utilities.
Thus, in addition to QF status, an IPP now can also apply to the FERC to be
granted status as an EWG. EWGs, however, are not exempt from regulation by the
FERC or state public utility commissions. The effect of such amendments is to
enhance the development of non-QFs that do not have to meet the fuel, production
and ownership requirements of PURPA. EME believes that the amendments benefit
EME by expanding its ability to own and operate facilities that do not qualify
for QF status, but may also result in increased competition because utilities
and other companies (e.g., equipment suppliers) may now develop facilities that
are not subject to the constraints of PUHCA. The Energy Policy Act also expanded
FERC authority to order utilities to grant transmission access to QFs and EWGs
and lifted restrictions on ownership of foreign utilities by U.S. companies.
Pursuant to the Energy Policy Act, FUCOs are also considered not to be electric
utility companies under PUHCA.
PUHCA
Under PUHCA, any corporation, partnership or other entity or organized group
that owns, controls or holds with power to vote 10% or more of the outstanding
voting securities of a "public-utility company" or a company that is a "holding
company" of a public utility company, is subject to registration with the
Securities and Exchange Commission (SEC) and regulation under PUHCA, unless
eligible for an exemption or unless an appropriate application is filed with,
and an order is granted by, the SEC declaring it not to be a holding company. A
registered public utility holding company regulated under PUHCA is required to
limit its utility operations to a single integrated utility system and to divest
any other operations not functionally related to the operation of that utility
system. Approval by the SEC is required for major financial commitments and
other business dealings of the regulated holding company or its subsidiaries.
As noted above, however, regulations have been adopted under PURPA and the
Energy Policy Act providing that QFs, EWGs and FUCOs are not public utility
companies. Accordingly, EME is not regulated as a "holding company" under PUHCA
because the power generation facilities owned by EME or in which EME has
investments are either QFs, EWGs or FUCOs. All international projects and
certain U.S. projects that EME is currently developing will be non-QF
independent power projects. EME intends for each such project to qualify as an
EWG or as a FUCO. Loss of EWG or FUCO status (like loss of QF status, as
discussed above) could also result in EME becoming subject to registration and
regulation as a public utility holding company under PUHCA and could trigger
defaults under covenants in project agreements. Loss of EWG or FUCO status on a
retroactive basis could lead to, among other things, fines and penalties and
could cause certain project contracts to be voidable.
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Natural Gas Act
Twenty of the domestic operating facilities that EME owns, operates or has
investments in are fueled by natural gas. Pursuant to the Natural Gas Act, the
FERC has jurisdiction over the sale, transportation and storage of natural gas
in interstate commerce. With respect to most transactions that do not involve
the construction of pipeline facilities, regulatory authorization can be
obtained on a self-implementing basis. However, pipeline rates for such services
are subject to continuing FERC oversight. Order No. 636, issued by the FERC in
April 1992 (and affirmed in Orders 636A and 636B issued, respectively, in August
and November 1992), mandated the restructuring of interstate natural gas
pipeline sales and transportation services and changed the terms and conditions
under which interstate pipelines provide transportation services, as well as the
rates pipelines may charge for such services. The restructuring required by the
rule included (i) the separation (unbundling) of a pipeline's sales,
transportation and storage services, (ii) the implementation of a straight
fixed-variable rate design methodology under which all of a pipeline's fixed
costs are recovered through its reservation charge, (iii) the implementation of
a capacity releasing mechanism under which holders of firm transportation
capacity on pipelines can release that capacity for resale by the pipeline, and
(iv) the opportunity for pipelines to recover 100% of their prudently incurred
costs (transition costs) associated with implementing the restructuring mandated
by the rule.
FPA
The FPA grants the FERC exclusive ratemaking jurisdiction over wholesale
sales of electricity in interstate commerce, including ongoing as well as
initial rate jurisdiction, which enables the FERC to revoke or modify previously
approved rates. Such rates may be based on a cost-of-service approach or may, in
competitive markets, be market-based. While qualifying facilities under PURPA
generally are exempt from the ratemaking and certain other provisions of the
FPA, EWGs and other non-QF independent power projects are subject to the FPA and
to FERC ratemaking jurisdiction, which may limit their flexibility in
negotiations with power purchasers. However, since such projects would not be
bound by PURPA's thermal energy use requirement, they have greater latitude in
site selection and facility size.
Currently, only three of EME's operating projects, Nevada Sun-Peak, Brooklyn
Navy Yard and Commonwealth Atlantic, are subject to FERC rate-making regulation
under the FPA. EME's future domestic non-QF independent power projects will
also be subject to FERC jurisdiction on rates.
STATE ENERGY REGULATION
State public utility commissions (PUCs) have broad jurisdiction over non-QF
independent power projects (including EWGs), which are considered public
utilities in many states. Such jurisdiction often includes the issuance of
certificates of public convenience and necessity (CPCNs) to construct a facility
as well as regulation of organizational, accounting, financial and other
corporate matters on an ongoing basis. QFs may also be required to obtain CPCNs
in some states. Although the FERC generally has exclusive jurisdiction over the
rates charged by a non-QF independent power project to its wholesale customers,
PUCs have the ability, in practice, to influence the establishment of such rates
by asserting jurisdiction over the purchasing utility's ability to pass-through
the resulting cost of purchased power to its retail customers. PUCs also have
the authority to determine avoided cost for QFs. In addition, states may assert
jurisdiction over the siting and construction of independent power projects and,
among other things, the issuance of securities, related party transactions and
the sale or other transfer of assets by
19
<PAGE>
these facilities. The actual scope of jurisdiction over independent power
projects by state PUCs varies from state to state.
In addition, state PUCs may seek to modify, suspend or terminate a QF's power
sales contract under certain circumstances. This could occur if the state PUC
determined that the pricing mechanism of the power sales contract is unfairly
high in light of the current prevailing market cost of power for the utility
purchasing the power. In such instance, the state PUC may attempt to alter the
terms of the power sales contract to reflect more accurately market conditions
for the prevailing cost of power. While EME believes that such attempts are not
common and that the state PUCs may not have any jurisdiction to modify the terms
of the wholesale power sales, there can be no assurance that the power sales
contracts of its projects will not be subject to adverse regulatory actions.
The CPUC has authorized the electric utilities in California to "monitor"
compliance by QFs with PURPA rules and regulation. However, the United States
Court of Appeals for the Ninth Circuit found in 1994 that a CPUC program was
preempted by PURPA insofar as it authorized utilities to determine that a QF was
not in compliance with PURPA rules and regulations, to then pay a reduced
avoided cost rate and to take other action contrary to a facility's status as a
QF. The court did, however, uphold reasonable monitoring of QF operating data.
Other states, such as New York, have also instituted QF monitoring programs.
EME buys and transports the natural gas used at its domestic facilities
through local distribution companies (LDCs). State PUCs have jurisdiction over
the transportation of natural gas by LDCs. Each state's regulatory laws are
somewhat different; however, all generally require the LDC to obtain approval
from the PUC for the construction of facilities and transportation services if
the LDC's generally applicable tariffs do not cover the proposed transaction.
LDC rates are usually subject to continuing PUC oversight.
TRANSMISSION OF WHOLESALE POWER
Projects that sell power to wholesale purchasers other than the local utility
to which the project is interconnected require the transmission of electricity
over power lines owned by others (wheeling). The prices and other terms and
conditions of transmission contracts are regulated by FERC, when the entity
providing the wheeling service is a jurisdictional public utility under the FPA.
Until 1992, FERC's ability to compel wheeling was very limited, and the
availability of voluntary wheeling service could be a significant factor in
determining whether a site was viable for project development.
FERC's authority under the FPA to require electric utilities to provide
transmission service on a case-by-case basis to QFs, EWGs, and other power
generators was expanded substantially by the Energy Policy Act. Furthermore, in
1996 FERC issued a rulemaking order, Order 888, in which FERC asserted the
power, under its authority to eliminate undue discrimination in transmission, to
compel all jurisdictional public utilities under the FPA to file open access
transmission tariffs consistent with a pro forma tariff drafted by FERC.
Although the pro forma tariff does not cover the pricing of transmission
service, Order 888 is expected to improve transmission access for independent
power producers such as EME.
RETAIL COMPETITION
In response to pressure from retail electric customers, particularly large
industrial users, the state commissions or state legislatures of most states are
considering, or have considered, whether to open the
20
<PAGE>
retail electric power market to competition. Retail competition is possible when
a customer's local utility agrees, or is required, to "unbundle" its
distribution service (e.g., the delivery of electric power through its local
distribution lines) from its transmission and generation service (e.g., the
provision of electric power from the utility's generating facilities or
wholesale power purchases). A few state commissions and legislatures have
already issued orders or passed legislation requiring utilities to begin to
offer unbundled retail distribution service (retail wheeling) beginning as soon
as 1998. Other states are expected to move toward retail competition by 2000.
The competitive pricing environment that will result from retail competition
may cause utilities to experience revenue shortfalls and deteriorating
creditworthiness. However, EME expects that most, if not all, state plans will
insure that utilities receive sufficient revenues, through a distribution
surcharge if necessary, to pay their obligations under existing long-term power
purchase contracts with QFs and EWGs. On the other hand, QFs and EWGs may be
subject to pressure to lower their contract prices in an effort to reduce the
"stranded investment" costs of their utility customers.
EME believes that, as a predominately low cost producer of electricity, it
will ultimately benefit from any increased competition that may arise from the
opening of the retail market. Although EME's EWGs are forbidden under PUHCA
from selling electric power at retail, its QFs will be permitted to market power
directly to large industrial users that could not previously be served, because
of local franchise laws or the inability to obtain retail wheeling. EME also
believes it will be an attractive supplier to power marketers serving the newly-
open retail markets.
ENVIRONMENTAL REGULATION
The construction and operation of power projects are subject to environmental
regulation by federal, state and local authorities in the United States and
regulatory authorities with jurisdiction over the projects located outside the
United States. EME believes that it is in substantial compliance with
environmental regulatory requirements and that maintaining compliance with
current requirements will not materially affect its financial condition or
results of operations. EME conducted a review of some of its sites in 1995 and
does not believe that a material liability exists as of December 31, 1997.
However, possible future developments, such as more stringent environmental laws
and regulations, could affect the costs and the manner in which EME conducts its
business. There can be no assurance that in such event EME would be able to
recover such increased costs from its customers or that its financial position
and results of operations would not be materially adversely affected.
Typically, environmental laws require a lengthy and complex process for
obtaining licenses, permits and approvals prior to construction and operation of
a project. Meeting all of the necessary requirements can delay or sometimes
prevent the completion of a proposed project as well as require extensive
modifications to existing projects, which may involve significant capital
expenditures.
In 1990, Congress passed amendments (the 1990 Amendments) to the Clean Air
Act that greatly expand the scope of federal regulations in several significant
respects. An EME project is anticipated to make capital expenditures of
approximately $11.6 million ($5.8 million is EME's share) from 1998 through 1999
in order to comply with the 1990 Amendments. Provisions related to
nonattainment, air toxins, permitting, enforcement and "acid rain" may affect
EME's projects; however, final details of all these programs have not been
issued by the United States Environmental Protection Agency and state agencies.
21
<PAGE>
The Comprehensive Environmental Response, Compensation, and Liability Act
(Superfund) requires the cleanup of sites from which there has been a release or
threatened release of hazardous substances. At the present time, EME is not
aware of any Superfund liability; however, there can be no assurance that EME
will not incur such liability in the future.
FOREIGN AND DOMESTIC OPERATIONS
- -------------------------------
A summary of EME's operations by geographic area including operating
revenues, net income (loss) and identifiable assets is incorporated herein by
reference from note 15 (Geographic Areas--Financial Data) of Notes to the
Consolidated Financial Statements.
ITEM 2. PROPERTIES
EME leases its principal office in Irvine, California. This lease is
approximately 92,600 square feet contained on six floors. The term of the lease
for approximately 65,500 square feet expires on December 31, 2002 with two five-
year options to extend. The term of the lease for the balance of approximately
27,100 square feet expires on December 31, 2002 with no options to extend. EME
also leases office space in Fairfax, Virginia and Washington, D.C. which is not
material. Subsidiaries of EME also lease office space in Barcelona, Spain;
Esenyurt, Turkey; Jakarta, Indonesia; London, England; Manila, Philippines;
Melbourne, Australia; Rome, Italy; and Singapore, none of which are material.
The following table shows the material properties owned or leased by EME, its
subsidiaries, or partnerships. Each property represents at least five percent of
EME's income before tax or is one in which EME has an investment balance greater
than $50 million. All of these properties are subject to mortgages or other
liens or encumbrances granted to the lenders providing financing for the plant
or project.
22
<PAGE>
DESCRIPTION OF PROPERTIES
<TABLE>
<CAPTION>
INTEREST
PLANT OR PROJECT LOCATION IN LAND PLANT DESCRIPTION
- ---------------- -------- ------- -----------------
<S> <C> <C> <C>
Brooklyn Navy Yard Brooklyn, New York Leased Natural gas-turbine cogeneration facility
First Hydro Dinorwig, Wales Owned Pumped-storage electric power facility
First Hydro Ffestiniog, Wales Owned Pumped-storage electric power facility
Kern River Oildale, California Leased Natural gas-turbine cogeneration facility
Loy Yang B Victoria, Australia Owned Coal-fired power facility
Midway-Sunset Fellows, California Leased Natural gas-turbine cogeneration facility
Paiton East Java, Indonesia Leased Coal-fired power facility under construction
Roosecote Barrow-in-Furness,Cumbria, UK Owned Combined cycle generation technology
Sycamore Oildale, California Leased Natural gas-turbine cogeneration facility
Watson Carson, California Leased Natural gas-turbine cogeneration facility
</TABLE>
ITEM 3. LEGAL PROCEEDINGS
PMNC Litigation -In February 1997, a civil action was commenced in the
---------------
Superior Court of the State of California, Orange County, entitled The Parsons
-----------
Corporation and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P., Mission
- -------------------------------------------------------------------------------
Energy New York, Inc. and B-41 Associates. L.P., Case No. 774980, in which
- -----------------------------------------------
plaintiffs assert general monetary claims under the Construction Turnkey
Agreement in the amount of $136,800,000. Brooklyn Navy Yard has also filed an
------------------------------------
action entitled Brooklyn Navy Yard Cogeneration Partners, L.P. v. PMNC, Parsons
- -------------------------------------------------------------------------------
Main of New York, Inc., Nab Construction Corporation, L.K. Comstock & Co., Inc.
- -------------------------------------------------------------------------------
and The Parsons Corporation, in the Supreme Court of the State of New York,
- ---------------------------
Kings County, Index No. 5966/97 asserting general monetary claims in excess of
$13,000,000 under the Construction Turnkey Agreement. EME believes that the
outcome of this litigation will not have a material adverse effect on its
consolidated financial position or results of operations.
EME experiences other routine litigation in the normal course of its
business. None of such pending litigation is expected to have a material adverse
effect on the consolidated financial position or results of operations of EME.
See "Certain Regulatory Matters--Environmental Regulation".
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Inapplicable.
23
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of the outstanding Common Stock of EME is, as of the date hereof, owned
by The Mission Group, which is a wholly owned subsidiary of Edison
International. There is no market for the Common Stock.
Dividends of the Common Stock will be paid when declared by the Board of
Directors of EME. EME made cash dividend payments to The Mission Group of $197
million and $150 million in 1997 and 1996, respectively. In 1997, a noncash
dividend of $78 million was also made to The Mission Group. At present, EME has
no plans to pay a dividend on the Common Stock.
In November 1994, Mission Capital, L.P. (Mission Capital), a limited
partnership of which EME is the sole general partner, issued 3.5 million 9-7/8%
Cumulative Monthly Income Preferred Securities, Series A (the Preferred
Securities) and EME issued $90,206,186 of 9-7/8% junior subordinated deferrable
interest debentures due 2024 (the Debentures) pursuant to a subordinated
indenture dated as of November 30, 1994 (the Subordinated Indenture) between EME
and The First National Bank of Chicago, as trustee. During August 1995, Mission
Capital issued 2.5 million 8-1/2% Cumulative Monthly Income Preferred
Securities, Series B (the Preferred Securities) and EME issued $64,432,990 of 8-
1/2% junior subordinated deferrable interest debentures due 2025 pursuant to the
Subordinated Indenture. EME issued a guarantee (the Guarantee) in favor of the
holders of the Preferred Securities, which guarantees the payments of
distributions declared on the Preferred Securities, payments upon a liquidation
of Mission Capital and payments on redemption with respect to any Preferred
Securities called for redemption by Mission Capital. So long as any Preferred
Securities remain outstanding, EME will not be able to declare or pay, directly
or indirectly, any dividend on, or purchase, acquire or make a distribution or
liquidation payment with respect to, any of its Common Stock if at such time (i)
EME shall be in default with respect to its payment obligations under the
Guarantee, (ii) there shall have occurred any event of default under the
Subordinated Indenture, or (iii) EME shall have given notice of its selection of
an extended interest payment period as provided in the Indenture and such
period, or any extension thereof, shall be continuing.
24
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
(IN MILLIONS) YEARS ENDED DECEMBER 31,
------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA
Operating revenues $ 975.0 $ 843.6 $ 467.3 $ 380.6 $ 290.5
Operating expenses 581.1 476.5 264.0 199.9 258.7(a)
-------- -------- -------- -------- ----------
Income from operations 393.9 367.1 203.3 180.7 31.8
Interest expense (223.5) (164.2) (93.1) (89.0) (33.5)
Interest and other income 53.9 40.7 33.1 38.8 4.7
Minority interest (38.8) (69.5) (48.3) (46.1) (11.4)
-------- -------- -------- -------- --------
Income (loss) before income taxes 185.5 174.1 95.0 84.4 (8.4)
Provision (credit) for income taxes 57.4 82.0 31.0 29.4 (4.2)
-------- -------- -------- -------- --------
Income (loss) before extraordinary loss and
cumulative effect of change in
accounting principle 128.1 92.1 64.0 55.0 (4.2)
Extraordinary loss on early extinguishingment
of debt, net of income tax benefit (13.1) -- -- -- --
Cumulative effect on prior periods of
change in accounting for income taxes -- -- -- -- 6.5
-------- -------- -------- -------- --------
Net income $ 115.0 $ 92.1 $ 64.0 $ 55.0 $ 2.3
======== ======== ======== ======== ========
<CAPTION>
DECEMBER 31,
(IN MILLIONS) ------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA
Assets $4,985.1 $5,152.5 $4,374.0 $2,842.9 $2,286.1
Current liabilities 339.8 270.9 199.8 170.9 116.3
Long-term obligations 2,532.1 2,419.9 1,839.0 1,159.0 962.6
Shareholder's equity 826.6 1,019.9 1,028.5 622.2 551.3
<CAPTION>
(IN MILLIONS) YEARS ENDED DECEMBER 31,
------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
PROPORTIONATE DATA (UNAUDITED)(C)
Operating revenues $1,502.2 $1,261.8 $ 865.4 $ 733.0 $ 712.8
Operating expenses 1,107.1 912.4 650.3 552.5 667.5(a)
-------- -------- -------- -------- --------
Income from operations 395.1 349.4 215.1 180.5 45.3
Interest expense (269.2) (212.8) (160.9) (138.5) (69.8)
Interest and other income 69.2 44.2 42.1 45.7 16.1
-------- -------- -------- -------- --------
Income (loss) before income taxes 195.1 180.8 96.3 87.7 (8.4)
Provision (credit) for income taxes 67.0 88.7 32.3 32.7 (4.2)
-------- -------- -------- -------- --------
Income (loss) before extraordinary loss and
cumulative effect of change in
accounting principle 128.1 92.1 64.0 55.0 (4.2)
Extraordinary loss on early extinguishment
of debt, net of income tax benefit (13.1) -- -- -- --
Cumulative effect on prior periods of
change in accounting for income taxes -- -- -- -- 6.5
-------- -------- -------- -------- --------
Net income $ 115.0 $ 92.1 $ 64.0 $ 55.0 $ 2.3
======== ======== ======== ======== ========
Operating cash flow(b) $ 559.3 $ 493.7 $ 326.5 $ 264.9 $ 202.9
======== ======== ======== ======== ========
</TABLE>
25
<PAGE>
(a) For the year ended December 31, 1993, operating expenses include special
charges of $98.4 million. Special charges include (1) costs (unreimbursed
development expenses and capitalized interest) associated with the
termination of negotiations for the Carbon II project in Mexico of $28.0
million; (2) a reserve of $52.4 million, which reflects the reduced value
of investments in five geothermal power plants due to lower gas price
forecasts; and (3) a reserve of $18.0 million for project development and
other costs.
(b) Income from operations plus depreciation, amortization and other non-cash
charges.
(c) Reflects EME's pro rata ownership interest in its energy projects and oil
and gas investments. Because significant 50% or less owned investments of
EME are not consolidated, EME believes that the discussion set forth below
of certain proportionate data facilitates an understanding and assessment of
its results of operations. Except for certain industries, proportionate
accounting is not in accordance with generally accepted accounting
principles.
Operating revenues increased in 1997 and 1996. The 1997 increase resulted
primarily from increases in electric revenues attributable to the start of
commercial operation of Loy Yang B Unit 2 in October 1996 and the Kwinana
project in December 1996 and higher energy revenues from First Hydro as a
result of increased utilization and higher pool prices, partially offset by
lower capacity prices in 1997. There were no comparable electric revenues
for Loy Yang B Unit 2 for the first nine months of 1996 or Kwinana for the
first 11 months of 1996. The 1996 increase in electric revenues over 1995
was primarily due to the acquisition of First Hydro in December 1995,
combined with its strong operating performance since acquisition, the start
of commercial operation of Loy Yang B Unit 2 and the Kwinana project in the
fourth quarter of 1996, both of which were previously under construction,
and the increase in ownership of Iberian Hy-Power from 34% to 100% in
January 1996. The 1997 increase in fuel expense and plant operations was
primarily due to commencement of commercial operations of the Kwinana
project in the fourth quarter of 1996 and increased generation and higher
prices at First Hydro. The 1997 increase in depreciation and amortization
resulted from commencement of commercial operations of Loy Yang B Unit 2 and
the Kwinana project in the fourth quarter of 1996. The 1996 increase
resulted from having no comparable expenses for First Hydro for the first 11
months of 1995 and no comparable expenses for Iberian Hy-Power, Loy Yang B
Unit 2 and Kwinana for fiscal year 1995.
Interest expense increased in 1997 and 1996, principally as a result of
higher project debt levels. Interest and other income increased in 1997 and
1996. The 1997 increase resulted from interest earned on higher cash
balances. The 1996 increase is primarily due to a pre-tax gain of $20
million on the sale of EME's interest in four operating geothermal projects.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
This Annual Report on Form 10-K includes certain forward-looking statements, the
realization of which may be affected by certain important factors discussed in
Management's Discussion and Analysis of Results of Operations and Financial
Condition thereunder and elsewhere herein.
GENERAL
- -------
Edison Mission Energy (EME) is one of the leading global producers of
electricity. Through its subsidiaries, EME is engaged in the business of
developing, acquiring, owning and operating electric power generation facilities
worldwide. EME's current investments include 53 projects totaling 9,325
megawatts (MW) of generation capacity, of which 7,403 MW are in operation and
1,922 MW are under construction.
EME's operating revenues are derived primarily from electric revenues and
equity in income from energy projects. Electric revenues accounted for 76%, 77%
and 64% of total operating revenues during
26
<PAGE>
1997, 1996 and 1995, respectively. Operating revenues also include equity in
income from oil and gas investments and revenue attributable to operation and
maintenance services.
Electric revenues are derived from consolidated results of operations of five
international entities. Equity in income from energy projects primarily relates
to EME's ownership interest of 50% or less in projects. The equity method of
accounting is generally used to account for the operating results of entities
over which a company has a significant influence but in which it does not have a
controlling interest. With respect to entities accounted for under the equity
method, EME recognizes its proportional share of the income or loss of such
entities.
ACQUISITIONS
- ------------
In 1992, a subsidiary of EME (together with other wholly owned affiliates of
EME) acquired 51% of the 1,000-MW Loy Yang B Power Station (Loy Yang B) from the
State Government of Victoria (State). In May 1997, a subsidiary of EME acquired
the State's 49% interest in Loy Yang B. In connection with the 1992
acquisition, the State Electricity Commission of Victoria (SECV) entered into a
30-year power purchase agreement with EME to purchase its share of the plant
output. Loy Yang B's principal assets are two 500-MW units fired by brown coal
located near Melbourne, Australia.
Consideration for the State's 49% interest consisted of (1) a cash payment of
approximately $64 million (84 million Australian dollars), (2) termination of
the existing power purchase agreement and other related agreements and (3)
entering into a new series of power sales-related contracts with the State
resulting in a total transaction value of approximately $686 million (900
million Australian dollars).
In December 1995, an indirect subsidiary of EME purchased all of the
outstanding shares of First Hydro Company (First Hydro) for approximately $1
billion (653 million pounds sterling). First Hydro's principal assets are two
pumped-storage electric power stations located in North Wales at Dinorwig and
Ffestiniog, which have a combined capacity of 2,088 MW.
This acquisition was funded through a combination of (i) a $621 million (400
million pounds sterling) credit facility with a bank and (ii) a $455 million
(295.3 million pounds sterling) equity investment funded from a combination of a
$350 million capital contribution from Edison International (EME's parent
company) and from EME's working capital and credit lines. In January 1996, the
400 million pounds sterling credit facility was canceled upon repayment of all
outstanding principal and accrued interest with proceeds from the issuance of
400 million pounds sterling of 9% Guaranteed Secured Bonds due on July 31, 2021.
In January 1996, EME purchased the remaining 66% of Iberian Hy-Power
Amsterdam B.V. (Iberian Hy-Power) for approximately $20 million, increasing its
ownership to 100%. Iberian Hy-Power owns interests in 18 run-of-the-river
hydroelectric facilities in Spain totaling 86 MW.
Each of the acquisitions has been accounted for utilizing the purchase
method. The purchase price was allocated to the assets acquired and liabilities
assumed based on their respective fair market values, with the excess being
allocated to goodwill. The consolidated statement of income for 1995 includes
operating results of First Hydro beginning in December 1995 and the consolidated
statement of income for 1997 reflects the operations under the new contracts and
the elimination of the minority interest of Loy Yang B beginning on May 9, 1997.
27
<PAGE>
RESULTS OF OPERATIONS
- ---------------------
Operating Revenues
Operating revenues increased significantly in 1997 and 1996. The 1997
increase resulted primarily from increases in electric revenues attributable to
the start of commercial operation of Loy Yang B Unit 2 in October 1996 and the
Kwinana project in December 1996 and higher energy revenues from First Hydro as
a result of increased utilization and higher pool prices, partially offset by
lower capacity prices in 1997. There were no comparable electric revenues for
Loy Yang B Unit 2 for the first nine months of 1996 and Kwinana for the first 11
months of 1996. The 1996 increase in electric revenues over 1995 was primarily
due to the acquisition of First Hydro in December 1995 combined with its strong
operating performance since acquisition, the start of commercial operation of
Loy Yang B Unit 2 and the Kwinana project in the fourth quarter of 1996, both of
which were previously under construction, and the increase in ownership of
Iberian Hy-Power from 34% to 100% in January 1996.
Electric revenues in the fourth quarter of 1997 were lower from fourth
quarter revenues in 1996 attributable to the Loy Yang B project due to the
restructuring of agreements associated with the 49% acquisition of Loy Yang B.
This also resulted in partially offsetting the higher electric revenues from the
Loy Yang B project in 1997.
Equity in income from energy projects rose 17% in 1997 over 1996, compared
with a 2% increase in 1996 over 1995. The 1997 increase is primarily
attributable to higher electric and steam revenue for several cogeneration
projects due to higher fuel gas prices upon which revenues are based. Equity in
income from oil and gas investments increased substantially in 1997 and 1996,
primarily due to higher gas prices in 1997 and higher oil and gas prices and
increased gas production in 1996.
A significant number of EME's domestic projects are located on the West
Coast. These projects generally have power sales contracts that provide for
higher payments during the summer months. Both First Hydro and Iberian Hy-Power
provide for higher electric revenues during the winter months. In addition,
First Hydro experienced higher energy sales in 1996 due to higher capacity
prices resulting from narrowing of the margin between the demand and available
generation forecast over the summer months and increased utilization. Unusual
weather conditions and unanticipated facility maintenance may have an effect on
future quarterly revenues.
Operating Expenses
Total operating expenses increased $104.6 million in 1997 and $212.4 million
in 1996. The increases for both periods were principally due to higher fuel
expense, plant operations, depreciation and amortization and administrative and
general expenses. Fuel and plant operations expense increased $62.8 million in
1997 and $140.4 million in 1996, depreciation and amortization expense increased
$12.9 million in 1997 and $44.3 million in 1996 and administrative and general
expenses increased $27.6 million in 1997 and $26.6 million in 1996.
The 1997 increase in fuel expense and plant operations was primarily due to
commencement of commercial operations of the Kwinana project in the fourth
quarter of 1996 and increased generation and higher prices at First Hydro.
28
<PAGE>
The 1997 increase in depreciation and amortization resulted from commencement
of commercial operations of Loy Yang B Unit 2 and the Kwinana project in the
fourth quarter of 1996. Loy Yang B's depreciation expense in 1997 was partially
reduced due to an extension in the useful life of Loy Yang B's plant and
equipment from approximately 30 years, the term of the previous power purchase
agreement, to 50 years (the projected economic life of the plant). The 1996
increase resulted from having no comparable expenses for First Hydro for the
first 11 months of 1995 and no comparable expenses for Iberian Hy-Power, Loy
Yang B Unit 2 and Kwinana for fiscal year 1995.
Both the 1997 and 1996 increase in administrative and general expenses is
attributable to an increase of approximately $54 million and $16 million,
respectively, in compensation expense as a result of charges related to EME's
phantom stock plan which is a part of Edison International Officer's Long-Term
Incentive Plan. The higher charges in 1997 were principally due to a substantial
appreciation in the value of EME's "phantom stock" over its exercise price. The
1997 increase in compensation expense was partially offset by lower project
development costs.
Other Income (Expense)
Interest and other income increased $6.5 million in 1997 over 1996, compared
with a decrease of $9.3 million in 1996 from 1995. The 1997 increase resulted
primarily from interest earned on higher cash balances. The 1996 decrease was
primarily due to income recognized in August 1995 for reimbursement of certain
1994 development expenses not previously recognized in settlement of EME's
remaining investment in Minera Carbonifera Rio Escondido.
During the second quarter of 1997, EME completed a sale of its ownership
interest in B.C. Star Partners (B.C. Star) for total cash proceeds of $71.2
million. EME recorded an after-tax gain of approximately $14 million on the
sale in April 1997. Based upon management's forecast of operating profits that
may have been realized from this operation, EME expects a minimal impact on its
future results of operations.
During the second quarter of 1996, CalEnergy Company, Inc., EME's partner in
four operating geothermal projects in California, purchased all of the stock of
four wholly owned subsidiaries of EME, which held interests in these projects.
The purchase price of $70 million resulted in an after-tax gain of $15.5
million. There was no impact on EME's future revenues as EME discontinued
recognizing earnings from these projects during 1993.
Interest incurred rose slightly in 1997 over 1996, compared to a $71.3
million increase in 1996 over 1995. The 1996 increase was due primarily to a
full year's inclusion of interest on the debt related to the First Hydro
acquisition and debt related to Iberian Hy-Power. Capitalized interest decreased
$51.9 million in 1997 from 1996, compared to an increase of $3.3 million in 1996
over 1995. The 1997 decrease is due to the completion of construction and
resultant commercial operation of Loy Yang B Unit 2 and the Kwinana project in
the fourth quarter of 1996 at which time the Company discontinued recording
capitalized interest related to these projects.
Dividends on preferred securities increased $3 million in 1996 over 1995.
The increase in 1996 was due to the inclusion of a full year of dividends on the
Series B preferred securities issued during the third quarter of 1995.
Minority interest expense decreased $30.7 million in 1997 from 1996, compared
with an increase of $21.2 million in 1996 over 1995. The 1997 decrease resulted
from the acquisition of the remaining 49%
29
<PAGE>
ownership interest in Loy Yang B in May 1997. The acquisition also contributed
to significantly lower minority interest expense in the fourth quarter of 1997
from 1996. The 1996 increase is due to Loy Yang B Unit 2 commencing commercial
operation in October 1996.
Provision for Income Taxes
EME had an effective tax provision rate of 30.9%, 47.1% and 32.6% in 1997,
1996 and 1995, respectively. The decrease in the 1997 effective tax rate was
primarily due to a reduction in corporate income taxes in the United Kingdom
(U.K.). The U.K. government decreased the corporate tax rate from 33% to 31%,
effective April 1, 1997. In accordance with Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes," this reduction in the U.K.
income tax rate resulted in an one-time reduction in income tax expense of
approximately $20 million to adjust the U.K. deferred income tax liability
(primarily related to First Hydro) to the new lower tax rate. The increase in
the 1996 effective tax rate was primarily due to higher international earnings
taxed at higher tax rates and certain expenditures not deductible in foreign
jurisdictions.
Extraordinary Loss
The early repayment of Loy Yang B's existing debt facilities of $713 million
in connection with the acquisition of the remaining 49% interest in May 1997
resulted in an extraordinary loss of $13.1 million (net of income tax benefit of
$8.6 million) attributable to the write-off of unamortized debt issue costs.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Cash provided by operating activities is derived primarily from distributions
from energy projects and dividends from investments in oil and gas. For the
year ended December 31, 1997, net cash provided by operating activities
decreased $35 million over 1996, compared with an increase of $144.6 million in
1996 from 1995. The 1997 decline primarily reflects an increase in working
capital requirements principally due to lower accounts receivable collections
from First Hydro. The 1996 improvement primarily reflects higher net income,
increased dividends from oil and gas investments and improved accounts
receivable collections principally attributable to First Hydro.
Dividends from investments in oil and gas increased $31.1 million in 1996
over 1995. The increase was principally due to increased dividends paid by Four
Star Oil & Gas Company as a result of higher earnings in 1996 over 1995.
Net cash provided by financing activities decreased $123.7 million during
1997 from 1996, compared with a substantial decrease during 1996 from 1995. The
1997 decrease was principally due to a reduction in financing activities and
higher cash dividends paid to Edison International. In 1997, the Loy Yang B
financing proceeds received in connection with the acquisition of the remaining
49% interest were primarily used to repay Loy Yang B's existing debt facilities.
In 1996, EME issued 400 million pounds sterling of 9% Guaranteed Secured Bonds
(U.S. $603.8 million), the proceeds of which were used to repay the 400 million
pounds sterling credit facility entered into in December 1995. In addition,
Edison Mission Energy Funding Corp., 99% owned by Broad Street Contract
Services, Inc. and 1% owned by EME, completed a sale of $450 million of senior
notes and bonds to institutional investors pursuant to the Rule 144A exemption
under the U.S. Securities Act of 1933 for non-public sales in December 1996. The
1996 decrease was primarily attributable to (1) a reduction in net borrowings
under
30
<PAGE>
EME's $500 million revolving credit facility in 1996, (2) a dividend paid to
Edison International of $150 million in 1996 compared with a $350 million
capital contribution received from Edison International in 1995 (pursuant to the
acquisition of First Hydro) and (3) proceeds of $62.5 million received in 1995
from the issuance of Series B Preferred Securities.
The Loy Yang B financing in 1997 consists of (1) a $373 million (490 million
Australian dollars) 15-year interest only term facility, (2) a $583 million (765
million Australian dollars) 20-year amortizing term facility with principal and
interest payments scheduled quarterly commencing September 30, 1998 and (3) an
$8 million (10 million Australian dollars) working capital facility with a term
equal to that of the 20-year amortizing term facility. The financing was
structured on a non-recourse basis. Lenders look solely to the operating cash
proceeds of Loy Yang B to repay the debt and have taken a security interest in
the Loy Yang B project assets.
In December 1996, Edison Mission Energy Funding Corp., 99% owned by Broad
Street Contract Services, Inc. and 1% owned by EME, completed a sale of $450
million of senior notes and bonds to institutional investors pursuant to the
Rule 144A exemption under the U.S. Securities Act of 1933 for non-public sales.
The senior notes and bonds are secured by the pledge of (i) notes issued by four
EME subsidiaries that own interests in four California cogeneration projects,
(ii) 99% of the capital stock of Edison Mission Energy Funding Corp. and (iii) a
guarantee issued by the four EME subsidiaries. The financing structure was
designed to pool and cross-collateralize available cash flow to the four EME
subsidiaries from the four projects thus providing for repayment of the senior
notes and bonds with available cash flow from the four projects. The
obligations of the four EME subsidiaries are non-recourse to EME.
The $450 million of securities issued by Edison Mission Energy Funding Corp.
consist of $260 million of Series A Notes and $190 million of Series B Bonds
which mature in September 2003 and September 2008, respectively. The Series A
Notes and Series B Bonds bear an interest rate of 6.77% and 7.33%, respectively,
and were rated BBB by Standard & Poor's Corporation and Baa1 by Moody's
Investors Services, Inc. The principal and interest payments under the notes
issued by the four EME subsidiaries are identical in terms to the Series A Notes
and Series B Bonds. The net proceeds from the sale of securities were used by
EME to repay borrowings under its $500 million revolving credit facility, retire
EME's 200 million Australian dollar credit facility, defease other project debt
and for other general corporate purposes.
Net cash used in investing activities decreased $149.2 million in 1997 from
1996, and significantly decreased in 1996 from 1995. The 1997 decline is
primarily due to an increase in proceeds received from loan repayments related
to Brooklyn Navy Yard and the Carbon II project and fewer loans made to energy
projects. The decrease in 1996 was principally due to the purchase of First
Hydro for approximately $1 billion in December 1995. Proceeds of $70 million
received from the sale of four of EME's operating geothermal facilities in 1996
also contributed to the decline in 1996 and is comparable to the proceeds of
$71.2 million received from the sale of EME's ownership interest in B.C. Star in
1997. EME invested $87.7 million, $119.4 million and $192.8 million in 1997,
1996 and 1995, respectively, in new plant and equipment principally related to
the Doga project in 1997 and the Loy Yang B Unit 2 and Kwinana projects in 1996
and 1995.
At December 31, 1997, EME had cash and cash equivalents of $585.9 million and
had available $388.6 million of borrowing capacity under a $500 million
revolving credit facility that expires in 2001. The credit facility provides
credit available in the form of cash advances or letters of credit, and bears
interest on advances under the London Interbank Offered Rate plus the applicable
margin as determined
31
<PAGE>
by EME's long-term debt ratings (0.175% margin at December 31, 1997), the Base
Rate (substantially similar to what is commonly known as the "prime" rate, which
was 8.5% at December 31, 1997), or on a competitive auction basis. This
borrowing capacity under the revolving credit facility may be reduced by
borrowings for firm commitments to contribute project equity and to fund capital
expenditures and construction costs of its project facilities.
FIRM COMMITMENTS TO CONTRIBUTE PROJECT EQUITY
<TABLE>
<CAPTION>
PROJECTS LOCAL CURRENCY U.S. (DOLLARS IN MILLIONS)
- -------- -------------- --------------------------
<S> <C> <C>
Paiton (i) 136
ISAB (ii) 244 billion Italian Lira 138
Doga (iii) 21
</TABLE>
(i) Paiton is a 1,230-MW coal-fired power plant under construction in East
Java, Indonesia. A wholly owned subsidiary of EME owns a 40% interest.
Equity contributions are currently being made and will continue until
commercial operation, which is currently scheduled for the first half of
1999.
(ii) ISAB is a 512-MW integrated gasification combined cycle power plant under
construction near Siracusa in Sicily, Italy. A wholly owned subsidiary of
EME owns a 49% interest. Equity will be contributed at commercial
operation, which is currently scheduled for late 1999.
(iii) Doga is a 180-MW gas-fired power plant under construction near Istanbul,
Turkey. A wholly owned subsidiary of EME owns an 80% interest. Equity
contributions are currently being made and will continue until commercial
operation, which is currently scheduled for 1999.
Firm commitments to contribute project equity could be accelerated due to
certain events of default as defined in the non-recourse project financing
facilities. Management has no reason to believe that these events of default
will occur requiring acceleration of the firm commitments.
CONTINGENT OBLIGATIONS TO CONTRIBUTE PROJECT EQUITY
<TABLE>
<CAPTION>
PROJECTS U.S. (DOLLARS IN MILLIONS)
- -------- --------------------------
<S> <C>
Paiton (i) 141
Doga (i) 19
All Other 21
</TABLE>
(i) Contingent obligations to contribute additional project equity to the
project would be based on events principally related to capital cost
overruns during the plant construction.
Management has no reason to believe that these contingent obligations or any
other contingent obligations to contribute project equity will be required.
OTHER COMMITMENTS AND CONTINGENCIES
Certain of EME's subsidiaries entered into indemnification agreements whereby
the subsidiaries agreed to repay capacity payments to the projects' power
purchasers, in the event the projects unilaterally terminate their performance
or reduce their electric power producing capability during the term of the power
contract. Obligations under these indemnification agreements as of December 31,
1997, if
32
<PAGE>
payment were required, would be $260 million. Management has no reason to
believe that the projects will either terminate their performance or reduce
their electric power producing capability during the term of the power
contracts.
Brooklyn Navy Yard is a 286-MW gas-fired cogeneration power plant in
Brooklyn, New York. A wholly owned subsidiary of EME owns 50% of the project.
On December 17, 1997, the Brooklyn Navy Yard project partnership completed a
$407 million permanent, non-recourse financing for the project. In February
1997, the construction contractor asserted general monetary claims under the
turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. (BNY)
for damages in the amount of $136.8 million. BNY has asserted general monetary
claims against the contractor. In connection with the 1997 refinancing, EME
agreed to indemnify the partnership and its partner from all claims and costs
arising from or in connection with the contractor litigation, which indemnity
has been assigned to the lenders. EME believes that the outcome of this
litigation will not have a material adverse effect on its consolidated financial
position or results of operations.
EME's projected construction expenditures that will be funded utilizing non-
recourse project financing are $80 million at December 31, 1997.
EME and its subsidiaries may incur additional obligations to make equity and
other contributions to projects in the future. EME believes that it will have
sufficient liquidity on both a short and long-term basis to fund pre-financing
project development costs, make equity contributions to partnerships, pay
corporate debt obligations and pay other administrative and general expenses as
they are incurred from (1) distributions from energy projects and dividends from
investments in oil and gas, (2) proceeds from the repayment of loans to energy
projects and (3) funds available from EME's revolving credit facility.
CHANGES IN INTEREST RATES, CHANGES IN ELECTRICITY POOL PRICING, FOREIGN CURRENCY
FLUCTUATIONS AND OTHER CONTRACTUAL OBLIGATIONS Changes in interest rates,
changes in electricity pool pricing and fluctuations in foreign currency
exchange rates can have a significant impact on EME's results of operations.
Interest rate changes affect the cost of capital needed to construct and finance
projects. EME has mitigated the risk of interest rate fluctuations by arranging
for fixed rate financing or variable rate financing with interest rate swaps or
other hedging mechanisms for the majority of its project financing. Interest
expense included $20.5 million, $6.2 million and $6.5 million for the years
1997, 1996 and 1995, respectively, as a result of interest rate hedging
mechanisms. EME has entered into several interest rate swap agreements whereby
the maturity date of the swaps occurs prior to the final maturity of the
underlying debt. EME does not believe that interest rate fluctuations will have
a materially adverse effect on its financial position or results of operations.
Projects in the U.K. sell their electrical energy and capacity through a
centralized electricity pool, which establishes a half-hourly clearing price
(also referred to as the "pool price") for electrical energy. The pool price is
extremely volatile and can vary by as much as a factor of ten or more over the
course of a few hours, due to the large differentials in demand according to the
time of day. First Hydro mitigates a significant portion of the market risk of
the pool by entering into contracts for differences (electricity rate swap
agreements), related to either the selling or purchasing price of power, whereby
a contract specifies a price at which the electricity will be traded, and the
parties to the agreement make payments, calculated based on the difference
between the price in the contract and the pool price for the element of power
under contract. These contracts can be sold in two structures: one-way
contracts, where a specified monthly amount is received in advance and
difference payments are made when the pool price is above the price specified in
the contract, and two-way contracts, where the counterparty pays First
33
<PAGE>
Hydro when the pool price is below that in the contract instead of a specified
monthly amount. These contracts act as a means of stabilizing production
revenues or purchasing costs by removing an element of First Hydro's net
exposure to pool price volatility. First Hydro's electric revenues were
increased by $36.9 million and decreased by $4.5 million for the years ended
December 31, 1997 and 1996, respectively, and decreased by $29 million in
December 1995, as a result of electricity rate swap agreements.
Loy Yang B sells its electrical energy through a centralized electricity pool
(the National Electricity Market) which provides for a system of generator
bidding, central dispatch and a settlements system based on a clearing market
for each half-hour of every day. The Victorian Power Exchange, operator and
administrator of the pool, determines a system marginal price each half hour.
To mitigate exposure to price volatility of the electricity traded into the
pool, Loy Yang B has entered into a number of financial hedges. From May 8,
1997 to December 31, 2000, approximately 53% to 64% of the plant output sold is
hedged under "Vesting Contracts" with the remainder of the plant capacity hedged
under the "State Hedge" described below. Vesting Contracts were put into place
by the State, between each generator and each distributor, prior to the
privatization of electric power distributors in order to provide more
predictable pricing for those electricity customers that were unable to choose
their electricity retailer. Vesting Contracts set base strike prices at which
the electricity will be traded, and the parties to the agreement make payments,
calculated based on the difference between the price in the contract and the
half-hourly pool clearing price for the element of power under contract. These
contracts can be sold as one-way or two-way contracts which are structured
similar to the electricity rate swap agreements described above. These
contracts are accounted for as electricity rate swap agreements. The State
Hedge is a long-term contractual arrangement based upon a fixed price commencing
May 8, 1997 and terminating October 31, 2016. The State guarantees SECV's
obligations under the State Hedge. Loy Yang B's electric revenues were
increased by $58.6 million for the year ended December 31, 1997 as a result of
hedging contract arrangements. The State Hedge and Vesting Contracts were
entered into in connection with the 49% acquisition of Loy Yang B in May 1997,
and therefore electric revenues were not impacted prior to 1997.
Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar
equivalent basis, the amount of EME's equity contributions to, and distributions
from, its foreign projects. As EME continues to expand into foreign markets,
fluctuations in foreign currency exchange rates can be expected to have a
greater impact on EME's results of operations in the future. At times, EME has
hedged a portion of its current exposure to fluctuations in foreign exchange
rates where it deems appropriate through financial derivatives, offsetting
obligations denominated in foreign currencies, and indexing underlying project
agreements to U.S. dollars or other indices reasonably expected to correlate
with foreign exchange movements. In addition, EME has used statistical
forecasting techniques to help assess foreign exchange risk and the
probabilities of various outcomes. There can be no assurance, however, that
fluctuations in exchange rates will be fully offset by hedges or that currency
movements and the relationship between certain macro economic variables will
behave in a manner that is consistent with historical or forecasted
relationships. Foreign exchange considerations for three major international
projects are discussed below.
The First Hydro project in the U.K. and the Loy Yang B project in Australia
have been financed in their local currency (pound sterling and Australian
dollar, respectively) thereby hedging the majority of their acquisition costs
against foreign exchange fluctuations. Furthermore, EME has evaluated the
return on the remaining equity portion of the investments with regard to the
likelihood of various foreign exchange scenarios. These analyses use market
derived volatilities, statistical correlations between certain variables, and
long-term forecasts to predict ranges of expected returns. Based upon these
34
<PAGE>
analyses, management believes that the investment returns for First Hydro and
Loy Yang B are adequately insulated from a broad range of foreign exchange
scenarios at this time. In 1996, EME repaid a 200 million Australian dollar
loan that was originally structured to hedge a portion of the foreign exchange
risk associated with EME's equity investment in the Loy Yang B project in
Australia. The decision to repay the loan was based on management's view that
the cost of the hedge was high relative to the current and expected volatility
of the Australian dollar.
Construction on the two-unit Paiton project is approximately 85% completed,
and commercial operation is expected in the first half of 1999. The tariff is
higher in the early years and steps down over time, and the tariff for the
Paiton project includes infrastructure to be used in common by other units at
the Paiton complex. The plant's output is fully contracted with the state-owned
electricity company, PT Perusahaan Listrik Negara (PLN), for payment in U.S.
dollars. The projected rate of growth of the Indonesian economy and the
exchange rate of Indonesian Rupiah into U.S. dollars have deteriorated
significantly since the Paiton project was contracted, approved and financed
with substantial finance and insurance support from the Export-Import Bank of
the United States, The Export-Import Bank of Japan, the U.S. Overseas Private
Investment Corporation and the Ministry of International Trade and Industry of
Japan. The Paiton project's senior debt ratings have been reduced from
investment grade to speculative grade based on the rating agencies' perceived
increased risk that PLN might not be able to honor the electricity sales
contract with Paiton. A Presidential decree has deemed some power plants, but
not including the Paiton project, subject to review, postponement or
cancellation.
EME will continue to monitor its foreign exchange exposure and analyze the
effectiveness and efficiency of hedging strategies in the future.
The electric power generated by EME's domestic operating projects is
generally sold to a limited number of electric utilities pursuant to long-term
(typically, 15 to 30 year) power sales contracts and is expected to result in
consistent cash flow under a wide range of economic and operating circumstances.
To accomplish this, EME structures its long-term contracts so that fluctuations
in fuel costs will produce similar fluctuations in electric and/or steam
revenues and by entering into long-term fuel supply and transportation
agreements.
ENVIRONMENTAL MATTERS OR REGULATIONS EME is subject to environmental regulation
by federal, state and local authorities in the U.S. and foreign regulatory
authorities with jurisdiction over projects located outside the U.S. EME
believes that it is in substantial compliance with environmental regulatory
requirements and that maintaining compliance with current requirements will not
materially affect its financial position or results of operations.
EME completed a review of some of its sites in 1995 and does not believe that
a material liability exists as of December 31, 1997. The implementation of
Clean Air Act Amendments is expected to result in increased operating expenses;
however, these increased operating expenses are not expected to have a material
impact on EME's financial position or results of operations.
YEAR 2000 ISSUE During 1997, EME completed the financial and informational
computer system review with no material costs incurred associated with resolving
the issue. The operational review will continue at all EME's power projects.
35
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements:
Report of Independent Public Accountants.
Consolidated Statements of Income for the years ended December 31, 1997, 1996
and 1995.
Consolidated Balance Sheets at December 31, 1997 and 1996.
Consolidated Statements of Shareholder's Equity for the years ended December
31, 1997, 1996 and 1995.
Consolidated Statements of Cash Flows for the years ended December 31, 1997,
1996 and 1995.
Notes to Consolidated Financial Statements.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
36
<PAGE>
EDISON MISSION ENERGY AND SUBSIDIARIES
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Edison Mission Energy:
We have audited the accompanying consolidated balance sheets of Edison
Mission Energy (a California corporation) and subsidiaries as of December 31,
1997 and 1996, and the related consolidated statements of income, shareholder's
equity and cash flows for each of the three years in the period ended December
31, 1997. These consolidated 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, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Edison
Mission Energy and subsidiaries as of 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.
Arthur Andersen LLP
Orange County, California
March 16, 1998
37
<PAGE>
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS)
<TABLE>
<CAPTION>
Years Ended December 31,
----------------------------------------
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
OPERATING REVENUES:
Electric revenues $ 744,675 $ 650,838 $ 297,200
Equity in income from energy projects 151,306 128,823 125,880
Equity in income from oil and gas 38,079 25,090 9,939
Operation and maintenance services 40,931 38,867 34,327
--------- --------- ---------
Total operating revenues 974,991 843,618 467,346
--------- --------- ---------
OPERATING EXPENSES:
Fuel 192,325 137,151 79,162
Plant operations 132,079 124,451 42,078
Operation and maintenance services 29,314 28,065 26,845
Depreciation and amortization 102,794 89,853 45,589
Administrative and general 124,576 96,954 70,354
--------- --------- ---------
Total operating expenses 581,088 476,474 264,028
--------- --------- ---------
Income from operations 393,903 367,144 203,318
--------- --------- ---------
OTHER INCOME (EXPENSE):
Interest and other income 27,306 20,766 30,034
Gain on sale of assets 26,642 19,986 3,144
Interest expense (210,311) (151,139) (83,050)
Dividends on preferred securities (13,167) (13,100) (10,095)
Minority interest (38,858) (69,547) (48,343)
--------- --------- ---------
Total other income (expense) (208,388) (193,034) (108,310)
--------- --------- ---------
Income before income taxes 185,515 174,110 95,008
Provision for income taxes 57,363 82,045 31,000
--------- --------- ---------
INCOME BEFORE EXTRAORDINARY LOSS $ 128,152 $ 92,065 $ 64,008
--------- --------- ---------
Extraordinary loss on early extinguishment
of debt, net of income tax benefit (13,126) -- --
--------- --------- ---------
NET INCOME $ 115,026 $ 92,065 $ 64,008
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
38
<PAGE>
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
December 31,
--------------------------
1997 1996
---------- -----------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 585,883 $ 383,634
Accounts receivable - trade 76,935 71,046
Accounts receivable - affiliates 18,139 10,798
Prepaid expenses and other 13,630 13,747
---------- ----------
Total current assets 694,587 479,225
---------- ----------
INVESTMENTS
Energy projects 852,688 794,646
Oil and gas 67,101 121,237
---------- ----------
Total investments 919,789 915,883
---------- ----------
PROPERTY, PLANT AND EQUIPMENT 3,142,551 3,401,006
Less accumulated depreciation and amortization 201,564 152,458
---------- ----------
Net property, plant and equipment 2,940,987 3,248,548
---------- ----------
OTHER ASSETS
Long-term receivables 25,957 91,567
Goodwill 312,606 334,481
Deferred financing costs and other 91,219 82,768
---------- ----------
Total other assets 429,782 508,816
---------- ----------
TOTAL ASSETS $4,985,145 $5,152,472
========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
39
<PAGE>
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
December 31,
-------------------------
1997 1996
------------ ----------
<S> <C> <C>
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates $ 13,381 $ 35,996
Accounts payable and accrued 208,411 118,824
liabilities
Interest payable 42,627 35,076
Current maturities of long-term 75,383 80,994
obligations ---------- ----------
Total current liabilities 339,802 270,890
---------- ----------
LONG-TERM OBLIGATIONS NET OF CURRENT 2,532,121 2,419,890
MATURITIES ---------- ----------
LONG-TERM DEFERRED LIABILITIES
Deferred taxes and tax credits 517,391 545,449
Deferred revenue 541,176 --
Other 68,951 39,049
---------- ----------
Total long-term deferred 1,127,518 584,498
liabilities ---------- ----------
Total liabilities 3,999,441 3,275,278
---------- ----------
MINORITY INTERESTS 9,102 707,289
---------- ----------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE
SECURITY OF PARTNERSHIP HOLDING
SOLELY PARENT DEBENTURES 150,000 150,000
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 6, 11 and 12)
SHAREHOLDER'S EQUITY
Common stock, no par value; 10,000
shares authorized; 100 shares issued
and outstanding 64,130 64,130
Additional paid-in capital 629,406 629,289
Retained earnings 102,620 262,594
Cumulative translation adjustments 30,446 63,892
---------- ----------
Total shareholder's equity 826,602 1,019,905
---------- ----------
TOTAL LIABILITIES AND SHAREHOLDER'S $4,985,145 $5,152,472
EQUITY ========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
40
<PAGE>
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
Additional Cumulative
Common Paid-in Retained Translation Shareholder's
Stock Capital Earnings Adjustments Equity
-------- ----------- ---------- ------------ --------------
<S> <C> <C> <C> <C> <C>
BALANCE AT DECEMBER 31, 1994 $64,130 $285,789 $ 256,521 $ 15,807 $ 622,247
Net income -- -- 64,008 -- 64,008
Cash contributions -- 350,000 -- -- 350,000
Issuances of stock by a
subsidiary -- (6,500) -- -- (6,500)
Translation adjustments -- -- -- (1,218) (1,218)
------- -------- --------- -------- ----------
BALANCE AT DECEMBER 31, 1995 64,130 629,289 320,529 14,589 1,028,537
Net income -- -- 92,065 -- 92,065
Cash dividends -- -- (150,000) -- (150,000)
Translation adjustments -- -- -- 49,303 49,303
------- -------- --------- -------- ----------
BALANCE AT DECEMBER 31, 1996 64,130 629,289 262,594 63,892 1,019,905
Net income -- -- 115,026 -- 115,026
Cash dividends -- -- (197,000) -- (197,000)
Non-cash dividend -- -- (78,000) -- (78,000)
Non-cash contribution -- 117 -- -- 117
Translation adjustments -- -- -- (33,446) (33,446)
------- -------- --------- -------- ----------
BALANCE AT DECEMBER 31, 1997 $64,130 $629,406 $ 102,620 $ 30,446 $ 826,602
======= ======== ========= ======== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
41
<PAGE>
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
Years Ended December 31,
--------------------------------------
1997 1996 1995
----------- ---------- -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 115,026 $ 92,065 $ 64,008
Adjustments to reconcile net income
to net cash provided by operating activities:
Equity in income from energy projects (151,306) (128,823) (125,880)
Equity in income from oil and gas (38,079) (25,090) (9,939)
Distributions from energy projects 133,643 125,717 158,226
Dividends from oil and gas 47,849 50,576 19,500
Depreciation and amortization 102,794 89,853 45,589
Deferred taxes and tax credits (7,994) 3,378 (4,559)
Gain on sale of assets (26,642) (19,986) (3,144)
Extraordinary loss on early extinguishment
of debt, net of tax 13,126 -- --
Decrease (increase) in accounts receivable (20,259) 31,356 (9,662)
Decrease in prepaid expenses and other 1,752 4,193 190
Increase in interest payable 7,857 18,635 3,293
Increase (decrease) in accounts 66,031 10,869 (10,692)
payable and accrued liabilities
Other, net 15,679 41,723 22,920
---------- --------- -----------
Net cash provided by operating activities 259,477 294,466 149,850
---------- --------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowing on long-term obligations 1,140,588 188,482 770,320
Payments on long-term obligations (882,446) (871,734) (67,643)
Issuance of Guaranteed Secured Bonds -- 603,840 --
Issuance of debt securities -- 414,275 --
Issuance of preferred securities -- -- 62,500
Cash dividends to parent (197,000) (150,000) --
Capital contribution from parent -- -- 350,000
---------- --------- -----------
Net cash provided by financing 61,142 184,863 1,115,177
activities ---------- --------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Investments in energy projects (62,034) (78,575) (98,403)
Loans to energy projects (63,406) (106,443) (243,894)
Payments of common stock of acquired companies (63,983) (34,640) (1,042,591)
Capital expenditures (87,706) (119,407) (192,808)
Proceeds from loan repayments 160,797 32,067 375,330
Proceeds from sale of assets 71,166 70,000 12,457
Other, net (51,965) (9,321) (1,358)
---------- --------- -----------
Net cash used in investing (97,131) (246,319) (1,191,267)
activities ---------- --------- -----------
Effect of exchange rate changes on cash (21,239) 13,084 (365)
---------- --------- -----------
Net increase in cash and cash equivalents 202,249 246,094 73,395
Cash and cash equivalents at beginning
of period 383,634 137,540 64,145
---------- --------- -----------
Cash and cash equivalents at end of period $ 585,883 $ 383,634 $ 137,540
========== ========= ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
42
<PAGE>
EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS)
NOTE 1. ORGANIZATION
- ---------------------
Edison Mission Energy (EME) is a wholly owned subsidiary of The Mission Group
(TMG), a wholly owned, non-utility subsidiary of Edison International, the
parent holding company of Southern California Edison Company (Edison). Through
its subsidiaries, EME is engaged in the business of developing, acquiring,
owning and operating electric power generation facilities worldwide.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
Consolidations
The consolidated financial statements include EME and its majority owned
subsidiaries, partnerships and a special purpose corporation. All significant
intercompany transactions have been eliminated. Certain prior year
reclassifications have been made to conform to the current year financial
statement presentation.
Management's 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 reported period.
Actual results could differ from those estimates.
Investments
Cash equivalents include time deposits and other investments totaling $218.9
million at December 31, 1997, with maturities of three months or less. All
investments are classified as available-for-sale.
Investments in energy projects and oil and gas that are 50% or less owned are
accounted for by the equity method. The majority of energy projects and all
investments in oil and gas are accounted for under the equity method at December
31, 1997.
Property, Plant and Equipment
Property, plant and equipment, including leasehold improvements and
construction in progress, are capitalized at cost and are principally comprised
of five energy entities' plants and related facilities. Depreciation and
amortization are computed by using the straight-line method over the useful life
of the property, plant and equipment and over the lease term for leasehold
improvements.
Useful lives for property, plant and equipment are as follows:
43
<PAGE>
Furniture and office equipment 3 - 10 years
Building, plant and equipment 25 - 50 years
Civil works 50 - 80 years
Capitalized leased equipment 10 - 30 years
Leasehold improvements Life of lease
Goodwill
Goodwill represents the cost incurred in connection with the purchase of
First Hydro Company (First Hydro) in excess of the fair value of the net assets
acquired in December 1995. This amount is being amortized over 40 years on a
straight-line basis. Accumulated amortization was $17.2 million and $9.3
million at December 31, 1997 and 1996, respectively.
Impairment of Investments and Long-Lived Assets
EME periodically evaluates the potential impairment of its investments in
projects and other long-lived assets (including goodwill) based on a review of
estimated future cash flows expected to be generated. If the carrying amount of
the investment or asset exceeds the amount of the expected future cash flows, an
impairment loss is recognized accordingly. Effective January 1, 1996, EME
adopted Statement of Financial Accounting Standards (SFAS) No. 121 "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of." This statement requires, among other things, that an impairment loss shall
only be recognized when the carrying amount of a long-lived asset exceeds the
expected future cash flows (undiscounted and without interest charges) and that,
when appropriate, the amount of loss to be recognized shall be measured as the
amount by which the carrying value exceeds the fair value of the asset. The
adoption of this statement did not have a material adverse effect on the
consolidated financial position or results of operations of EME.
Capitalized Interest
Interest incurred on funds borrowed by EME to finance project construction is
capitalized. Capitalization of interest is discontinued when the projects are
completed and deemed operational. Such capitalized interest is included in
investment in energy projects and property, plant and equipment.
Capitalized interest is amortized over the depreciation period of the major
plant and facilities for the respective project.
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Interest incurred $222.8 $215.5 $144.2
Interest capitalized (12.5) (64.4) (61.1)
------ ------ ------
$210.3 $151.1 $ 83.1
====== ====== ======
</TABLE>
Income Taxes
EME is included in the consolidated federal income tax and combined state
franchise tax returns of Edison International. EME calculates its income tax
provision on a separate company basis under a tax sharing arrangement with TMG,
which in turn has an agreement with Edison International. Tax benefits
44
<PAGE>
generated by EME and used in the Edison International consolidated tax return
are recognized by EME without regard to separate company limitations.
EME accounts for income taxes using the asset-and-liability method, wherein
deferred tax assets and liabilities are recognized for future tax consequences
of temporary differences between the carrying amounts and the tax bases of
assets and liabilities using enacted rates. Investment and energy tax credits
are deferred and amortized over the term of the power-purchase agreement of the
respective project. Income tax accounting policies are discussed further in
Note 8.
Project Development Costs
EME capitalizes only the direct costs incurred in developing new projects.
These costs consist of professional fees, salaries, permits, bids and other
directly related development costs incurred by EME before a partnership or joint
venture is formed to develop the project. The capitalized costs are amortized
over the life of operational projects or charged to expense if management
determines the costs to be unrecoverable.
Deferred Financing Costs
Bank, legal and other direct costs incurred in connection with obtaining
financing are deferred and amortized as interest expense on a basis which
approximates the effective interest rate method over the term of the related
debt. Accumulated amortization amounted to $1.7 million in 1997 and $6.9
million in 1996.
Deferred Revenue
Certain revenues on power sales contracts are deferred and amortized to
income utilizing the unit-of-production method over the term of the contracts.
Financial Instruments
EME enters into interest rate swap, cap and collar agreements to manage its
interest rate exposure. The related net interest rate differentials to be paid
or received are recorded as adjustments to interest expense. In addition, EME
enters into electricity rate swap agreements to manage its exposure to the U.K.
and Australia market (pool) price volatilities. The related price differentials
to be paid or received are currently recorded as adjustments to electric
revenues or fuel expenses.
Translation of Foreign Financial Statements
Assets and liabilities of most foreign operations are translated at end of
period rates of exchange and the income statements are translated at the average
rates of exchange for the year. Gains or losses resulting from foreign currency
transactions are normally included in other income in the consolidated
statements of income. Foreign currency transaction gains and (losses) amounted
to $(2.9) million, $0.6 million and $(0.4) million, for 1997, 1996 and 1995,
respectively. Gains or losses from translation of foreign currency financial
statements are included in shareholder's equity.
45
<PAGE>
Stock-based Compensation
EME measures compensation expense relative to stock-based compensation by the
intrinsic-value method.
NOTE 3. ACQUISITIONS
- ---------------------
In 1992, a subsidiary of EME (together with other wholly owned affiliates of
EME) acquired 51% of the 1,000-MW Loy Yang B Power Station (Loy Yang B) from the
State Government of Victoria (State). In May 1997, a subsidiary of EME acquired
the State's 49% interest in Loy Yang B. In connection with the 1992
acquisition, the State Electricity Commission of Victoria (SECV) entered into a
30-year power purchase agreement with EME to purchase its share of the plant
output. Loy Yang B's principal assets are two 500-MW units fired by brown coal
located near Melbourne, Australia.
Consideration for the State's 49% interest consisted of (1) a cash payment of
approximately $64 million (84 million Australian dollars), (2) termination of
the existing power purchase agreement and other related agreements and (3)
entering into a new series of power sales-related contracts with the State
resulting in a total transaction value of approximately $686 million (900
million Australian dollars).
In December 1995, an indirect subsidiary of EME purchased all of the
outstanding shares of First Hydro for approximately $1 billion (653 million
pounds sterling). First Hydro's principal assets are two pumped-storage
electric power stations located in North Wales at Dinorwig and Ffestiniog, which
have a combined capacity of 2,088 MW.
This acquisition was funded through a combination of (i) a $621 million (400
million pounds sterling) credit facility with a bank (see Note 6) and (ii) a
$455 million (295.3 million pounds sterling) equity investment funded from a
combination of a $350 million capital contribution from Edison International and
from EME's working capital and credit lines.
Each of the acquisitions has been accounted for utilizing the purchase
method. The purchase price was allocated to the assets acquired and liabilities
assumed based on their respective fair market values with the excess being
allocated to goodwill. The excess of the purchase price over the carrying value
of the net assets acquired relating to the Loy Yang B acquisition was allocated
to property, plant and equipment. The consolidated statement of income for 1995
includes operating results of First Hydro beginning in December 1995 and the
consolidated statement of income for 1997 reflects the operations under the new
contracts and the elimination of the minority interest of Loy Yang B beginning
on May 9, 1997.
The following unaudited pro forma data summarizes the consolidated results of
operations for the periods indicated as if the acquisition of First Hydro had
occurred at the beginning of 1995 and the acquisition of the 49% interest in Loy
Yang B had occurred at the beginning of 1996 and 1997. The pro forma data gives
effect to certain adjustments including electric revenues, fuel expense,
depreciation and amortization, interest expense and related income tax
adjustments. These results have been prepared for comparative purposes only and
do not purport to be indicative of what would have occurred had the acquisitions
been made at the beginning of 1997, 1996 or 1995, or of the results which may
occur in the future.
46
<PAGE>
<TABLE>
<CAPTION>
(Unaudited)
Years Ended December 31,
------------------------
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Operating revenues $939.9 $731.2 $690.4
Income before extraordinary loss 143.9 88.4 80.8
Net income 130.8 88.4 80.8
</TABLE>
The table below summarizes additional stock acquisitions by EME or its wholly
owned subsidiaries during 1997, 1996 and 1995.
<TABLE>
<CAPTION>
Percentage Purchase
Date Acquired By Acquisition Acquired Price
- ---- ----------- ----------- ---------- --------
<S> <C> <C> <C> <C>
Energy Projects
January 31, 1996 MEC Indonesia B.V. P.T. Paiton Energy Company 7.5% $10.2
January 23, 1996 MEC International B.V. Iberian Hy-Power Amsterdam B.V. 66.0% 19.5
August 8, 1995 MEC Indo Coal B.V. P.T. Adaro Indonesia 10.0% 19.0
Oil and Gas
August 1, 1996 Edison Mission Energy Oil Four Star Oil & Gas Company 4.4% 4.9
& Gas (EMEO&G) (Four Star)
January 1, 1995 EMEO&G Four Star 6.0% 8.8
</TABLE>
NOTE 4. INVESTMENTS
- --------------------
Investments in Energy Projects
Investments in energy projects, generally 50% or less owned partnerships and
corporations, accounted for by the equity method are as follows:
<TABLE>
<CAPTION>
December 31,
------------
1997 1996
---- ----
<S> <C> <C>
Domestic energy projects:
Equity investment $411.5 $419.6
Notes receivable 145.3 202.6
------ ------
Subtotal 556.8 622.2
International energy projects:
Equity investment and advances 295.9 172.4
------ ------
Total $852.7 $794.6
====== ======
</TABLE>
EME's subsidiaries have provided loans or advances related to certain
projects. One loan totaled $96.2 million and bears interest at a 10% rate.
Another loan amounting to $26.3 million, comprising promissory notes bearing
interest at 5% payable semiannually, is due in April 2008. Loans to three other
domestic projects amounted to $22.8 million at December 31, 1997, and bear
interest at variable rates (8.5% to 12.5%).
47
<PAGE>
The following table presents summarized financial information of the
investments in energy projects accounted for by the equity method:
<TABLE>
<CAPTION>
Years Ended December 31,
-------------------------------
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Revenue $1,593.4 $1,383.3 $1,128.9
Expenses 1,294.7 1,083.1 862.4
-------- -------- --------
Net income $ 298.7 $ 300.2 $ 266.5
======== ======== ========
<CAPTION>
December 31,
-------------------
1997 1996
-------- --------
<S> <C> <C>
Current assets $ 507.7 $ 480.0
Noncurrent assets 4,523.7 3,653.9
-------- --------
Total assets $5,031.4 $4,133.9
======== ========
Current liabilities $ 750.9 $ 614.0
Noncurrent liabilities 2,986.2 2,341.7
Equity 1,294.3 1,178.2
-------- --------
Total liabilities and equity $5,031.4 $4,133.9
======== ========
</TABLE>
The majority of noncurrent liabilities are comprised of project financing
arrangements that are non-recourse to EME.
The following table presents, as of December 31, 1997, the energy projects
accounted for by the equity method that represent at least five percent (5%) of
EME's income before tax or in which EME has an investment balance greater than
$50 million.
<TABLE>
<CAPTION>
Energy Project Location Investment Operating Status
- -------------- -------- ---------- ----------------
<S> <C> <C> <C>
Paiton East Java, Indonesia $230.1 Coal-fired facility under construction
Watson Carson, CA 121.4 Operating cogeneration facility
Brooklyn Navy Yard Brooklyn, NY 98.5 Operating cogeneration facility
Sycamore Bakersfield, CA 69.2 Operating cogeneration facility
Kern River Bakersfield, CA 51.3 Operating cogeneration facility
Midway-Sunset Fellows, CA 40.8 Operating cogeneration facility
</TABLE>
Investments in Oil and Gas
At December 31, 1997, EME had one 46.85% owned and one 50% owned investments
in oil and gas. These investments are accounted for utilizing the equity
method. The difference between the carrying value of one oil and gas investment
and the underlying equity in the net assets amounted to $42.9 million at
December 31, 1997. The difference is being amortized on a unit of production
basis
48
<PAGE>
over the life of the reserves. The following table presents summarized
financial information of the investments in oil and gas:
<TABLE>
<CAPTION>
Years Ended December 31,
--------------------------------
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Operating revenues $304.7 $313.7 $230.5
Operating expenses 197.4 222.3 187.5
------ ------ ------
Operating income 107.3 91.4 43.0
Provision for income taxes 18.5 17.2 2.9
------ ------ ------
Net income (before non-operating items) 88.8 74.2 40.1
Non-operating expense, net (12.8) (12.0) (12.5)
------ ------ ------
Net income $ 76.0 $ 62.2 $ 27.6
====== ====== ======
December 31,
------------
1997 1996
------ ------
Current assets $ 94.3 $109.1
Noncurrent assets 417.6 526.8
------ ------
Total assets $511.9 $635.9
====== ======
Current liabilities $ 49.5 $ 46.2
Noncurrent liabilities 309.4 336.2
Deferred income taxes and other liabilities 64.5 59.0
Equity 88.5 194.5
------ ------
Total liabilities and equity $511.9 $635.9
====== ======
</TABLE>
The undistributed earnings of investments accounted for by the equity method
were $150.1 million in 1997 and $138.9 million in 1996.
Long-Term Receivables
Long-term receivables include notes receivable from EME's former partner in
the Carbon II power plant. In December 1997, EME's former partner made a
prepayment of $65 million reducing notes receivable to $21.2 million at December
31, 1997. These notes are secured by a surety bond. Interest on these notes is
payable quarterly at LIBOR plus 2% (7.8% at December 31, 1997), with the
remaining principal due in November 1999.
49
<PAGE>
NOTE 5. PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------
Property, plant and equipment consist of the following:
<TABLE>
<CAPTION>
December 31,
--------------------
1997 1996
-------- --------
<S> <C> <C>
Buildings, plant and equipment $1,857.8 $2,198.9
Civil works 1,002.2 996.0
Construction in progress 83.8 0.6
Capitalized leased equipment 198.8 205.5
-------- --------
3,142.6 3,401.0
Less accumulated depreciation and
amortization 201.6 152.5
-------- --------
$2,941.0 $3,248.5
======== ========
</TABLE>
NOTE 6. FINANCIAL INSTRUMENTS
- ------------------------------
Long-Term Obligations
Long-term obligations include both corporate debt and non-recourse project
debt, whereby lenders rely on specific project assets to repay such obligations.
Long-term obligations consist of the following:
<TABLE>
<CAPTION>
December 31,
-------------------------
1997 1996
------------- ---------
<S> <C> <C>
EME (parent only):
Senior Notes, net:
due 1999 (7.75%) $ 99.8 $ 99.7
due 2002 (8.125%) 99.3 99.1
Edison Mission Energy Funding Corp.:
Series A Notes, net
due 1997-2003 (6.77%) 231.5 258.4
Series B Bonds, net
due 2004-2008 (7.33%) 188.7 188.7
First Hydro Finance Plc (First Hydro
Finance):
400 million pounds sterling
Guaranteed Secured Bonds
due 2021 (9%) 657.1 684.9
Iberian Hy-Power project:
Project credit facilities
due 2003 (MIBOR + 1.5 to 2%)
(7.836% to 8.336% at 12/31/96) -- 85.7
</TABLE>
50
<PAGE>
<TABLE>
<S> <C> <C>
Term Loan
due 2012 (MIBOR + 0.75%)
(5.594% at 12/31/97) 78.1 --
Project Credit Facility
due 2003 (9.408%) 26.5 --
Loy Yang B project:
Latrobe Project Facilities Agreement
due 2008 (BER + 1.75 to 1.95%)
(7.737% to 7.937% at 12/31/96) -- 744.6
Energy Capital Partnership Credit Agreement
due 2012-2017 (BBR + 0.3 to 1.0%)
(5.398% to 6.098% at 12/31/97) 823.6 --
Roosecote project:
Capital lease obligation (see Note 12) 68.2 90.3
Term Loan and Guarantee Facility
due 2005 (sterling LIBOR + 0.6%)
(8.288% at 12/31/97) 83.1 58.0
Kwinana project:
Kwinana Bank Debt
due 2012 (BER + 1.2%)
(6.265% at 12/31/97) 67.2 104.2
Doga project:
Doga Bank Debt
due 2010 (LIBOR + 3.08%)
(8.889% at 12/31/97) 59.3 --
Other long-term obligations 125.1 87.3
-------- --------
Subtotal 2,607.5 2,500.9
Current maturities of long-term (75.4) (81.0)
obligations -------- --------
Total $2,532.1 $2,419.9
======== ========
</TABLE>
At December 31, 1997, EME had available $388.6 million of borrowing capacity
and approximately $111.4 million in letters of credit issued under a $500
million revolving credit facility that expires in 2001.
On December 20, 1996, Edison Mission Energy Funding Corp., 99% owned by Broad
Street Contract Services, Inc. and 1% owned by EME, completed a sale of $450
million of senior notes and bonds to institutional investors pursuant to the
Rule 144A exemption under the U.S. Securities Act of 1933 for non-public sales.
The senior notes and bonds are secured by the pledge of (i) notes issued by four
EME subsidiaries that own interests in four California cogeneration projects,
(ii) 99% of the capital
51
<PAGE>
stock of Edison Mission Energy Funding Corp. and (iii) a guarantee issued by the
four EME subsidiaries. The financing structure was designed to pool and cross-
collateralize available cash flow to the four EME subsidiaries from the four
projects thus providing for repayment of the senior notes and bonds with
available cash flow from the four projects. The obligations of the four EME
subsidiaries are non-recourse to EME.
The $450 million of securities issued by Edison Mission Energy Funding Corp.
consist of $260 million of Series A Notes and $190 million of Series B Bonds
which mature in September 2003 and September 2008, respectively. The Series A
Notes and Series B Bonds bear an interest rate of 6.77% and 7.33%, respectively.
The principal and interest payments under the notes issued by the four EME
subsidiaries are identical in terms to the Series A Notes and Series B Bonds.
The net proceeds from the sale of securities were used by EME to repay
borrowings under its $500 million revolving credit facility, retire EME's 200
million Australian dollar credit facility, defease other project debt and for
other general corporate purposes.
In January 1996, First Hydro Finance issued 400 million pounds sterling of 9%
Guaranteed Secured Bonds (Bonds) at par due on July 31, 2021. First Hydro
Finance will commence funding a redemption reserve for principal repayment
beginning in 2017 with interest payments due on a semi-annual basis beginning
July 1996. The Bonds are secured by the two pumped-storage electric power
stations located in North Wales. The net proceeds of $604 million (396 million
pounds sterling) received, along with other funds held by First Hydro Finance,
were used to repay the borrowings under the 400 million pounds sterling credit
facility entered into by First Hydro Finance in December 1995 in connection with
the First Hydro acquisition. EME has two letters of credit under its corporate
credit facility in the amount of $29.6 million (18 million pounds sterling) to
meet a requirement for six months of interest in a bond interest reserve account
and $19.7 million (12 million pounds sterling) revenue support letter of credit
due to expire in 1998.
In May 1997, EME closed financing of $964 million (1.265 billion Australian
dollars) in connection with the acquisition of the remaining 49% interest, the
proceeds received were used to repay Loy Yang B's existing debt facilities of
$713 million (935.5 million Australian dollars) with the balance used to finance
the Loy Yang B 49% acquisition and to return funds to various affiliates of EME.
The financing consists of (1) a $373 million (490 million Australian dollars)
15-year interest only term facility, (2) a $583 million (765 million Australian
dollars) 20-year amortizing term facility with principal and interest payments
scheduled quarterly commencing September 30, 1998 and (3) an $8 million (10
million Australian dollars) working capital facility with a term equal to that
of the 20-year amortizing term facility. The financing was structured on a non-
recourse basis. Lenders look solely to the operating cash proceeds of Loy Yang
B to repay the debt and have taken a security interest in the Loy Yang B project
assets. The early repayment of Loy Yang B's existing debt facilities of $713
million resulted in an extraordinary loss of $13.1 million (net of income tax
benefit of $8.6 million) attributable to the write-off of unamortized debt issue
costs.
Annual maturities on long-term debt at December 31, 1997, for the next five
years, excluding capital leases (see Note 12) are summarized as follows: 1998 -
$54.9 million; 1999 - $183.2 million; 2000 - $82.2 million; 2001 - $81.3
million; 2002 - $189.7 million.
Certain cash balances are restricted from being used primarily to pay or
dividend to EME amounts required for debt payments, letter of credit expenses
and permitted project costs. The total restricted cash was $59.5 million at
December 31, 1997 and $17.8 million at December 31, 1996.
52
<PAGE>
Debt service reserves classified in Other Assets (including reserves for
interest on annual lease payments) were $44.7 million at December 31, 1997 and
$13.2 million at December 31, 1996.
Each of EME's direct or indirect subsidiaries is organized as a legal entity
separate and apart from EME and its other subsidiaries. Any asset of any such
subsidiary may not be available to satisfy the obligations of EME 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 EME or affiliates
thereof.
Other Financial Instruments
Projects in the U.K. and a project in Australia sell their electrical energy
and capacity through a centralized electricity pool, which establishes a half-
hourly clearing price (also referred to as the "pool price") for electrical
energy. The pool price is extremely volatile and in the U.K. can vary by as
much as a factor of 10 or more over the course of a few hours, due to the large
differentials in demand according to the time of day. First Hydro mitigates a
significant portion of the market risk of the pool by entering into contracts
for differences (electricity rate swap agreements), related to either the
selling or purchasing price of power, whereby a contract specifies a price at
which the electricity will be traded, and the parties to the agreement make
payments, calculated based on the difference between the price in the contract
and the pool price for the element of power under contract. These contracts can
be sold in two structures: one-way contracts, where a specified monthly amount
is received in advance and difference payments are made when the pool price is
above the price specified in the contract, and two-way contracts, where the
counterparty pays First Hydro when the pool price is below that in the contract
instead of a specified monthly amount. These contracts act as a means of
stabilizing production revenues or purchasing costs by removing an element of
First Hydro's net exposure to pool price volatility. The Roosecote project has
avoided the pool price volatility by entering into a long-term power sales
contract that provides for contract pricing.
Loy Yang B has entered into a number of financial hedges to mitigate exposure
to price volatility of the electricity traded into the pool. From May 8, 1997
to December 31, 2000, approximately 53% to 64% of the plant output sold is
hedged under "Vesting Contracts" with the remainder of the plant capacity hedged
under the "State Hedge" described below. Vesting Contracts were put into place
by the State, between each generator and each distributor, prior to the
privatization of electric power distributors in order to provide more
predictable pricing for those electricity customers that were unable to choose
their electricity retailer. Vesting Contracts set base strike prices at which
the electricity will be traded, and the parties to the agreement make payments,
calculated based on the difference between the price in the contract and the
half-hourly pool clearing price for the element of power under contract. These
contracts can be sold as one-way or two-way contracts which are structured
similar to the electricity rate swap agreements described above. These
contracts are accounted for as electricity rate swap agreements. The State
Hedge is a long-term contractual arrangement based upon a fixed price commencing
May 8, 1997 and terminating October 31, 2016. The State guarantees SECV's
obligations under the State Hedge.
EME's risk management policy allows for the use of these contracts and other
derivative financial instruments to limit financial exposure on its investments
and to manage exposure to fluctuations in interest rates, foreign exchange rates
and energy prices but prohibits the use of these instruments for speculative
investment purposes. EME does not hold or issue financial instruments for
trading purposes.
53
<PAGE>
EME had the following derivative financial instruments at December 31, 1997
and 1996, except where noted:
<TABLE>
<CAPTION>
Category Contract Amount/Terms Purpose
- -------- --------------------- -------
<S> <C> <C>
INTEREST RATE SWAPS
EME (parent only): $200 million Convert fixed-rate
expiring in 1999 debt of 7.75% and
($100 million) and 8.125% to a floating
2002 ($100 million) rate, such floating
rate capped at 9.0%
$45 million Convert fixed-rate
expiring in 1999, debt of 9.875% to a
corresponding floating rate
preferred
securities due 2024
Iberian Hy-Power project: 10.9 billion Change floating-rate
Spanish pesetas debt to fixed rates
(12/31/96) (U.S. ranging from 8.4% to
$84 million) 11.38%
expired in November
1997
Roosecote project: 45 million pounds Change floating-rate
sterling (12/31/96) debt to a fixed rate
(U.S. $77 million) of 12.4%
expired in July 1997
Kwinana project: 40.8 million Change floating-rate
Australian dollars debt to a fixed rate
(12/31/97) (U.S. of 10.98%
$27 million); 41.9
million Australian
dollars (12/31/96)
(U.S. $33 million);
expiring in 2007
Loy Yang B project: 1.2 billion Change floating-rate
Australian dollars debt to fixed rates
(U.S. $781 million) ranging from 7.51% to
expiring 2002-2007 7.93%
INTEREST RATE COLLAR
Iberian Hy-Power project: 11.7 billion Change interest rate
Spanish pesetas exposure to float
(U.S. $77 million) within range from 4.5%
expiring in 1999 minimum to 7.5% maximum
ELECTRICITY RATE SWAPS
First Hydro project: Approximately 1,685 Change the variable
MW related to market electricity
winter months sales rates to fixed
(October through rates
March) and 759 MW
related to summer
months (April
through September)
of electrical
generation under
selling pricing
contracts
(12/31/97); 1,735
MW related to
winter months and
1,185 MW related to
summer months
(12/31/96) expiring
at various dates
through 2000
</TABLE>
54
<PAGE>
Approximately 410 Change the variable
MW related to market electricity
winter months and rates to fixed rates
200 MW related to
summer months of
electricity under
purchasing pricing
contracts
(12/31/97); 416 MW
related to both
winter and summer
months (12/31/96)
expiring at various
dates through 1999
Loy Yang B project: Approximately 920 Change the variable
MW of electrical market electricity
generation under sales rates to fixed
selling pricing rates
contracts
(12/31/97) expiring
at various dates
through 2016
Fair values of financial instruments were:
<TABLE>
<CAPTION>
December 31,
--------------------------------------------
1997 1996
------------------ --------------------
Carrying Fair Carrying Fair
Instruments: Amount Value Amount Value
------ ----- ------ -----
<S> <C> <C> <C> <C>
Long-term receivables $ 26.0 $ 27.6 $ 91.6 $ 99.9
Electricity rate swap
agreements -- 77.1 -- 26.8
Long-term obligations 2,532.1 2,715.6 2,419.9 2,434.4
Interest rate swap/collar
agreements -- (68.1) -- (17.6)
</TABLE>
The fair values for long-term receivables, interest rate swap agreements, the
interest rate collar agreement and long-term obligations are based primarily on
quoted market prices. The carrying amounts reported for cash equivalents
approximate fair value due to their short maturities.
The fair value of the electricity rate swap agreements entered into by First
Hydro and Loy Yang B has been estimated by discounting the future cash flows on
the difference between the average aggregate contract price per MW and a
forecasted market price per MW, multiplied by the amount of MW sales remaining
under contract.
In addition, Iberian Hy-Power has entered into a forward-starting interest
rate swap in order to fix the interest rate on a portion of the long-term debt
outstanding. The swap period commences on December 15, 1999 and matures on
December 15, 2007. The notional amount of the swap is based on an amortizing
loan profile. The notional amount at December 15, 1999 is 10.8 billion Spanish
pesetas (U.S. $71 million). As of December 31, 1997, the fair value of this
swap was a negative one million dollars which has been reflected in the table
above.
55
<PAGE>
Credit Risk
EME's financial instruments and power sales contracts involve elements of
credit risk. Credit risk relates to the risk of loss that EME would incur as a
result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The counterparties to financial instruments and
contracts consist of a number of major financial institutions and domestic and
foreign utilities. EME attempts to mitigate this risk by entering into contracts
with counterparties that have a strong capacity to meet their contractual
obligations and by monitoring the credit quality of these financial institutions
and utilities. In addition, EME enters into contracts whereby the structure of
the contracts minimizes its credit exposure. Accordingly, EME does not
anticipate any material impact to its financial position or results of
operations as a result of counterparty nonperformance.
The electric power generated by EME's domestic operating projects that are
generally sold to a limited number of electric utilities pursuant to long-term
(typically, 15 to 30 year) power sales contracts (see Note 13) are expected to
result in consistent cash flows under a wide range of economic and operating
circumstances. To accomplish this, EME structures its long-term contracts so
that fluctuations in fuel costs will produce similar fluctuations in electric
and/or steam revenues and by entering into long-term fuel supply and
transportation agreements. In addition, EME has plants located in different
geographic areas in order to mitigate the effects of regional markets, economic
downturns or unusual weather conditions.
NOTE 7. COMPANY-OBLIGATED MANDATORILY REDEEMABLE SECURITY OF PARTNERSHIP
- -------------------------------------------------------------------------
HOLDING SOLELY PARENT DEBENTURES
- --------------------------------
During November 1994, Mission Capital, L.P., a limited partnership in which
EME is the sole general partner and a wholly owned subsidiary of EME is the
limited partner, issued 3.5 million of 9-7/8% Cumulative Monthly Income
Preferred Securities, Series A, at a price of $25 per security. These
securities are redeemable at the option of Mission Capital, L.P., in whole or in
part, beginning November 1999 with mandatory redemption in 2024 at a redemption
price of $25 per security plus accrued and unpaid distributions.
During August 1995, Mission Capital, L.P., issued 2.5 million of 8-1/2%
Cumulative Monthly Income Preferred Securities, Series B, at a price of $25 per
security. These securities are redeemable at the option of Mission Capital,
L.P., in whole or in part, beginning August 2000 with mandatory redemption in
2025 at a redemption price of $25 per security plus accrued and unpaid
distributions.
NOTE 8. INCOME TAXES
- ---------------------
Current and Deferred Taxes
Income tax expense includes the current tax liability from operations and the
change in deferred income taxes during the year. The components of the net
accumulated deferred income tax liability were:
56
<PAGE>
<TABLE>
<CAPTION>
December 31,
-----------------
1997 1996
------- ------
<S> <C> <C>
Deferred tax assets:
Reserves and other items not currently deductible $ 92.0 $ 64.5
Loss carryforwards 8.9 129.9
Deferred income 191.6 --
Dividends in excess of equity earnings 22.4 22.6
Other 17.1 10.0
------ ------
Total 332.0 227.0
------ ------
Deferred tax liabilities:
Basis differences 820.0 741.3
Tax credits, net 29.0 30.7
Other 0.4 0.4
------ ------
Total 849.4 772.4
------ ------
Deferred taxes and tax credits, net $517.4 $545.4
====== ======
Loss carryforwards, primarily Australian, total $45 million at December 31,
1997, with no expiration date.
The components of income before income taxes are as follows:
<CAPTION>
Years Ended December 31,
---------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
U.S. $ 39.0 $ 40.6 $ 50.6
Foreign 146.5 133.5 44.4
------ ------ ------
Total $185.5 $174.1 $ 95.0
====== ====== ======
The provision for income taxes is comprised of the following:
<CAPTION>
Years Ended December 31,
--------------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Current
Federal $ (2.4) $ 33.1 $ 23.9
State (10.2) 6.7 4.5
Foreign 78.3 38.8 7.2
------ ------ ------
Total current 65.7 78.6 35.6
------ ------ ------
Deferred
Federal 14.3 (17.9) (13.0)
State 9.0 0.4 (2.4)
Foreign (31.6) 20.9 10.8
------ ------ ------
Total deferred (8.3) 3.4 (4.6)
------ ------ ------
Provision for income taxes $ 57.4 $ 82.0 $ 31.0
====== ====== ======
</TABLE>
57
<PAGE>
The components of the deferred tax provision (credit), which arise from tax
credits and timing differences between financial and tax reporting, are
presented below:
<TABLE>
<CAPTION>
Years Ended December 31,
---------------------------
1997 1996 1995
-------- ------- -------
<S> <C> <C> <C>
Basis differences $ 102.6 $ 55.3 $ 47.1
Loss carryforwards 121.0 (41.2) (23.4)
Deferred income (197.9) -- --
State tax deduction (0.2) (2.9) 2.1
Reserves and other items not currently deductible (27.6) 8.7 (24.1)
Elimination of book income (7.0) (10.0) (6.8)
Dividends in excess of equity earnings 0.2 (9.2) (0.5)
Other 0.6 2.7 1.0
------- ------ ------
Total deferred provision (credit) $ (8.3) $ 3.4 $ (4.6)
======= ====== ======
</TABLE>
Variations from the 35% federal statutory rate are as follows:
<TABLE>
<CAPTION>
Years Ended December 31,
---------------------------
1997 1996 1995
-------- ------- -------
<S> <C> <C> <C>
Expected provision for federal income taxes $ 64.9 $ 60.9 $ 33.2
Increase (decrease) in the provision for taxes
resulting from:
State tax - net of federal deduction (0.8) 4.4 1.4
Dividends received deduction (8.2) (7.9) (4.0)
Amortization of tax credits (1.7) (8.6) (1.6)
Production tax credits -- -- (1.0)
Taxes on foreign operations at 2.0 17.3 2.5
different rates
Book and tax basis differences 3.5 15.4 --
Other (2.3) 0.5 0.5
------- ------ ------
Total provision for income taxes $ 57.4 $ 82.0 $ 31.0
======= ====== ======
Effective tax rate 30.9% 47.1% 32.6%
======= ====== ======
</TABLE>
NOTE 9. EMPLOYEE BENEFIT PLANS
- ------- ----------------------
U.S. employees of EME are eligible for various benefit plans of Edison
International. Certain EME Australian, U.K. and Spanish subsidiaries also
participate in their own respective defined benefit pension plans.
Pension Plans
The noncontributory, defined benefit pension plans, administered by trustees,
cover employees who fulfill minimum service requirements. Benefits are based on
years of credited service and average base salary. Annual contributions meet
the minimum legal funding requirements and do not exceed the maximum deductible
for income taxes. Prior service costs from pension plan amendments are funded
58
<PAGE>
over 30 and 15 years for the U.S. plan and Australian plan, respectively. There
are no prior service costs included in the U.K. and Spanish plans. Plan assets
are primarily U.S., U.K. and Australian common stock, corporate and government
bonds and short-term investments.
In 1996, EME recorded special termination benefits in connection with its
special voluntary early retirement program. The special termination benefit was
paid directly from the employer's assets and plan assets.
Funded status of pension plans:
<TABLE>
<CAPTION>
December 31,
-------------------------------------------------------
1997 1996 1997 1996
-------- ------- -------- --------
U.S. Plan Non U.S. Plans
-------------------- -------------------------
<S> <C> <C> <C> <C> <C>
Actuarial present value of benefit obligations:
Vested benefits $10.3 $ 7.4 $26.8 $23.3
Nonvested benefits 3.5 1.7 1.1 0.8
----- ----- ----- -----
Accumulated benefit obligation 13.8 9.1 27.9 24.1
Value of projected future compensation levels 6.7 5.6 2.2 2.0
----- ----- ----- -----
Projected benefit obligation $20.5 $14.7 $30.1 $26.1
===== ===== ===== =====
Fair value of plan assets $16.6 $ 4.9 $28.3 $24.1
===== ===== ===== =====
Assets less than projected benefit obligations (3.9) (9.8) (1.8) (2.0)
Unrecognized net loss (gain) (0.8) 5.4 0.7 (0.2)
Unrecognized prior service cost 0.5 0.6 -- --
Unrecognized net obligation 1.4 1.5 -- --
----- ----- ----- -----
Pension liability $(2.8) $(2.3) $(1.1) $(2.2)
===== ===== ===== =====
Discount rate 7.0% 7.75% 5.0% - 6.75% 6.5% - 8.0%
Rate of increase in future compensation 5.0% 5.5% 3.5% - 4.75% 4.5% - 5.5%
Expected long-term rate of return on plan assets 8.0% 8.0% 5.0% - 9.0% 8.5% - 9.0%
</TABLE>
Components of pension expense were:
<TABLE>
<CAPTION>
Years Ended December 31,
-----------------------------------------------------------
1997 1996 1995 1997 1996 1995
------ ------ ------ ------ ------ ------
U.S. Plan Non U.S. Plans
------------------------ -------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost for benefits earned $ 1.8 $ 2.0 $ 2.3 $ 3.5 $ 3.5 $ 0.5
Interest cost on projected benefit
obligation 1.1 1.5 1.1 1.9 1.7 0.1
Actual return on plan assets (1.1) (1.7) (0.8) (3.4) (1.5) (0.2)
Net amortization and deferral 0.2 0.9 0.1 (0.6) (2.4) 0.1
----- ----- ----- ----- ----- -----
Pension expense 2.0 2.7 2.7 1.4 1.3 0.5
Special termination benefits -- 0.9 -- -- -- --
----- ----- ----- ----- ----- -----
Net pension expense $ 2.0 $ 3.6 $ 2.7 $ 1.4 $ 1.3 $ 0.5
===== ===== ===== ===== ===== =====
</TABLE>
59
<PAGE>
In 1995, First Hydro employees were included as part of The National Grid
Company plc (NGC) defined benefit pension plan (Electricity Supply Pension
Scheme), administered by a trustee, which provides pension and other related
benefits. Effective April 1, 1996, First Hydro employees were transferred into
the First Hydro Group of the Electricity Supply Pension Scheme. An actuarial
valuation for the U.K. plan, separate from NGC, was first completed for 1996
and, therefore, comparative amounts for 1995 were not included in the table
above. Pension expense totaled $0.1 million for December 1995.
Postretirement Benefits Other Than Pensions
U.S. employees retiring at or after age 55 who have at least 10 years of
service, are eligible for postretirement health care, dental, life insurance and
other benefits. Health care benefits are subject to deductibles, copayment
provisions and other limitations.
The components of postretirement benefits other than pension expense were:
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------------
1997 1996 1995
----- ------ ------
<S> <C> <C> <C>
Service costs for benefits earned $ 1.2 $ 1.2 $ 1.2
Interest cost on benefit obligation 0.7 0.7 0.6
Amortization of transition obligation 0.1 0.2 0.2
----- ----- -----
Net expense 2.0 2.1 2.0
Special termination benefits -- 0.5 --
----- ----- -----
Total expense $ 2.0 $ 2.6 $ 2.0
===== ===== =====
</TABLE>
A reconciliation of the plan's funded status with the recorded liability is
presented below:
<TABLE>
<CAPTION>
December 31,
---------------
1997 1996
------ ------
<S> <C> <C>
Accumulated benefit obligation $11.7 $11.4
===== =====
Fair value of plan assets $ -- $ --
===== =====
Accumulated benefit obligation in excess of
plan assets $11.7 $11.4
Unrecognized transition obligation (2.0) (2.2)
Unrecognized net loss (1.1) (4.1)
----- -----
Recorded liability $ 8.6 $ 5.1
===== =====
Discount rate 7.0% 7.75%
</TABLE>
The assumed rate of future increases in the per capita cost of health care
benefits is 8.5% for 1998, gradually decreasing to 5.25% for 2004 and beyond.
Employee Stock Plans
- --------------------
A 401(k) plan is maintained to supplement eligible U.S. employees' retirement
income. The plan received EME contributions of $0.7 million in 1997, 1996 and
1995.
60
<PAGE>
In addition to the defined benefit plans described above, certain U.K.
subsidiaries of EME sponsor a defined contribution plan. Annual contributions
are based on 8 to 8.6 percent of covered employees' salaries. Contribution
expense for the subsidiaries totaled approximately $0.3 million in 1997 and $0.2
million in 1996 and 1995.
NOTE 10. STOCK COMPENSATION PLANS
- ----------------------------------
Under Edison International Officer's Long-Term Incentive Compensation Plan
(LTIP), shares of Edison International common stock were reserved for potential
issuance to key EME employees in various forms, including the exercise of stock
options. Under these programs, there are currently outstanding to officers and
senior managers of EME, options on 320,590 shares of Edison International Common
Stock of which 61,300, 57,900 and 31,700 were granted in 1997, 1996 and 1995,
respectively. Options on Edison International stock include a dividend
equivalent feature.
Compensation expense recorded under the stock-compensation program was $0.5
million, $0.7 million and $0.3 million for 1997, 1996 and 1995, respectively.
The weighted-average fair value of options granted during 1997, 1996 and 1995
was $7.62 per share option, $6.27 per share option and $6.92 per share option,
respectively. The weighted-average remaining life of options outstanding as of
December 31, 1997, 1996 and 1995 was seven years.
The fair value for each option granted during 1997, 1996 and 1995, reflecting
the basis for the pro forma disclosures, was determined on the date of grant
using the Black-Scholes option-pricing model. The following assumptions were
used in determining fair value through the model:
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Expected life 7 years 7 years 8 years
Risk-free interest rate 6.5% 5.5% 7.9%
Expected volatility 17% 17% 17%
</TABLE>
The recognition of dividend equivalents results in no dividends assumed for
purposes of fair-value determination. Stock-based compensation expense under
the "fair-value" method of accounting prescribed by SFAS No. 123 "Stock-Based
Compensation" would have resulted in no material change to EME's reported net
income for 1997, 1996 and 1995, but is not necessarily indicative of future
income statement effects.
Phantom Stock Options
EME, as a part of the LTIP, issued "phantom stock" option performance awards
to key employees commencing in 1994. Each phantom stock option may be exercised
to realize any appreciation in the value of one hypothetical share of EME stock
over its exercise price. Exercise prices for EME phantom stock are escalated on
an annually-compounded basis over the grant price by 12%. The value of the
phantom stock is recalculated annually as determined by a formula linked to the
value of its portfolio of investments less general and administrative costs. The
options have a 10-year term with one-third of the total award vesting in each of
the first three years of the award term. Compensation expense recorded with
respect to phantom stock options was $70 million, $16.1 million and $0.8 million
in 1997, 1996 and 1995, respectively.
61
<PAGE>
NOTE 11. COMMITMENTS AND CONTINGENCIES
- ---------------------------------------
Firm Commitments to Contribute Project Equity
<TABLE>
<CAPTION>
Projects Local Currency U.S. Currency
- -------- -------------- -------------
<S> <C> <C>
Paiton (i) $136
ISAB (ii) 244 billion Italian Lira 138
Doga (iii) 21
</TABLE>
(i) Paiton is a 1,230-MW coal-fired power plant under construction in East
Java, Indonesia. A wholly owned subsidiary of EME owns a 40% interest. Equity
contributions are currently being made and will continue until commercial
operation, which is currently scheduled for the first half of 1999.
(ii) ISAB is a 512-MW integrated gasification combined cycle power plant under
construction near Siracusa in Sicily, Italy. A wholly owned subsidiary of EME
owns a 49% interest. Equity will be contributed at commercial operation, which
is currently scheduled for late 1999.
(iii) Doga is a 180-MW gas-fired power plant under construction near Istanbul,
Turkey. A wholly owned subsidiary of the Company owns an 80% interest. Equity
contributions are currently being made and will continue until commercial
operation, which is currently scheduled for 1999.
Firm commitments to contribute project equity could be accelerated due to
certain events of default as defined in the non-recourse project financing
facilities. Management has no reason to believe that these events of default
will occur requiring acceleration of the firm commitments.
Contingent Obligations to Contribute Project Equity
<TABLE>
<CAPTION>
Projects U.S. Currency
- -------- -------------
<S> <C>
Paiton (i) $141
Doga (i) 19
All Other 21
</TABLE>
(i) Contingent obligations to contribute additional project equity to the
project would be based on events principally related to capital cost
overruns during the plant construction.
Management has no reason to believe that these contingent obligations or any
other contingent obligations to contribute project equity will be required.
Other Commitments and Contingencies
Certain of EME's subsidiaries entered into indemnification agreements whereby
the subsidiaries agreed to repay capacity payments to the projects' power
purchasers, in the event the projects unilaterally terminate their performance
or reduce their electric power producing capability during the term of the power
contract. Obligations under these indemnification agreements as of December 31,
1997, if payment were required, would be $260 million. Management has no reason
to believe that the projects
62
<PAGE>
will either terminate their performance or reduce their electric power producing
capability during the term of the power contracts.
Brooklyn Navy Yard is a 286-MW gas-fired cogeneration power plant in
Brooklyn, New York. A wholly owned subsidiary of EME owns 50% of the project.
On December 17, 1997, the Brooklyn Navy Yard project partnership completed a
$407 million permanent, non-recourse financing for the project. In February
1997, the construction contractor asserted general monetary claims under the
turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. (BNY)
for damages in the amount of $136.8 million. BNY has asserted general monetary
claims against the contractor. In connection with the 1997 refinancing, EME
agreed to indemnify the partnership and its partner from all claims and costs
arising from or in connection with the contractor litigation, which indemnity
has been assigned to the lenders. EME believes that the outcome of this
litigation will not have a material adverse effect on its consolidated financial
position or results of operations.
EME's projected construction expenditures that will be funded utilizing non-
recourse project financing are $80 million at December 31, 1997.
Litigation
EME is routinely involved in litigation arising in the normal course of
business. While the results of such litigation cannot be predicted with
certainty, management, based on advice of counsel, does not believe that the
final outcome of any pending litigation will have a material adverse effect on
EME's financial position or results of operations.
Environmental Matters or Regulations
EME is subject to environmental regulation by federal, state and local
authorities in the U.S. and foreign regulatory authorities with jurisdiction
over projects located outside the U.S. EME believes that it is in substantial
compliance with environmental regulatory requirements and that maintaining
compliance with current requirements will not materially affect its financial
position or results of operations.
EME completed a review of some of its sites in 1995 and does not believe that
a material liability exists as of December 31, 1997. The implementation of
Clean Air Act Amendments is expected to result in increased operating expenses;
however, these increased operating expenses are not expected to have a material
impact on EME's financial position or results of operations.
NOTE 12. LEASE COMMITMENTS
- ---------------------------
EME leases office space, property and equipment under noncancelable lease
agreements that expire in various years through 2063. The capital lease
obligation is primarily for a project located in the U.K. A group of banks
provides a guarantee on the performance of the capital lease obligation under a
term loan and guarantee facility agreement. The facility agreement provides for
an aggregate of $188.5 million in a guarantee to the lessor and in loans to the
project. As of December 31, 1997, the loan obligation stands at $83.1 million,
which is secured by the plant assets of $19 million owned by the project and a
debt service reserve of $5.5 million.
Future minimum payments for operating and capital leases at December 31, 1997,
are:
63
<PAGE>
<TABLE>
<CAPTION>
Year Ending December 31: Operating Capital
Leases Leases
--------- -------
<S> <C> <C>
1998 $ 6.7 $27.0
1999 5.4 27.1
2000 4.1 27.0
2001 3.9 0.2
2002 3.6 0.2
Thereafter 18.9 0.5
----- -----
Total future commitments $42.6 82.0
=====
Amount representing interest (9.65%) 13.8
-----
Net Commitments $68.2
=====
</TABLE>
Operating lease expense amounted to $6.7 million in 1997, $6.3 million in 1996
and $3.9 million in 1995.
NOTE 13. RELATED PARTY TRANSACTIONS
- ------------------------------------
Certain administrative services such as payroll and employee benefit
programs, all performed by Edison International or Edison employees, are shared
among all affiliates of Edison International and the costs of these corporate
support services are allocated to all affiliates, including EME. Costs are
allocated based on one of the following formulas: percentage of time worked,
equity in investment and advances, number of employees, or multi-factor
(operating revenues, operating expenses, total assets and number of employees).
In addition, services of Edison International or Edison employees are sometimes
directly requested by EME and such services are performed for EME's benefit.
Labor and expenses of these directly requested services are specifically
identified and billed at cost. Management believes the allocation methodologies
utilized are reasonable. EME made reimbursements for the cost of these programs
and other services, which amounted to $23.4 million, $18.3 million and $15.9
million in 1997, 1996 and 1995, respectively.
EME records accruals for tax liabilities and/or tax benefits which are
settled quarterly according to a series of tax sharing agreements as described
in Note 2. Under these agreements, EME recognized a tax benefit of $12.6
million for 1997 and tax liabilities of $39.8 million and $28.4 million for 1996
and 1995, respectively (see Note 8).
Certain EME subsidiaries have ownership in partnerships that sell electricity
generated by their project facilities to Edison and others under the terms of
long-term power-purchase agreements. Sales by such partnerships to Edison under
these agreements amounted to $579.6 million in 1997, $517.1 million in 1996, and
$657.3 million in 1995.
64
<PAGE>
NOTE 14. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION
- -----------------------------------------------------------
<TABLE>
<CAPTION>
Years Ended December 31,
-------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Cash paid:
Interest (net of amount capitalized) $218.1 $131.5 $ 76.4
Income taxes $ 62.3 $ 45.9 $ 41.6
<CAPTION>
Years Ended December 31,
-------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Details of companies acquired:
Fair value of assets acquired $667.1 $152.7 $1,761.1
Liabilities assumed 603.1 118.1 718.5
------ ------ --------
Net cash paid for acquisitions $ 64.0 $ 34.6 $1,042.6
====== ====== ========
</TABLE>
Non-Cash Investing and Financing Activities
The amount of construction in progress financed by the minority owner in
the Loy Yang B joint venture was $0.1 million in 1997, $32.7 million in 1996 and
$77.4 million in 1995.
In June 1997, EME made a noncash dividend of $78 million to its parent
company, TMG, a wholly owned, non-utility subsidiary of Edison International.
The noncash dividend is in the form of a promissory note with interest at LIBOR
plus 0.275% (6.09% at December 31, 1997) paid on quarterly basis and principal
due on June 30, 2007.
NOTE 15. GEOGRAPHIC AREAS - FINANCIAL DATA
- -------------------------------------------
EME operates predominately in one industry segment: electric power
generation. Electric power and steam generated domestically is sold primarily
under long-term contracts to electric utilities and industrial steam users
located in the U.S. Excluding the U.K. and a project in Australia, electric
power generated overseas is sold primarily under long-term contracts to electric
utilities located in the country where the power is generated. Projects located
in the U.K. and a project in Australia sell their energy and capacity production
through a centralized electricity pool. These projects enter into short -
and/or long-term contracts to hedge against the volatility of price fluctuations
in the pool.
<TABLE>
<CAPTION>
Asia Corporate/
U.S. Pacific Europe Other(1) Total
------ -------- --------- ----------- --------
<S> <C> <C> <C> <C> <C>
1997
- ----
Electric & operating revenues $ 8.9 $ 312.8 $ 463.9 $ -- $ 785.6
Equity in income from investments 182.7 3.5 0.2 3.0 189.4
------ -------- -------- ------ --------
Total operating revenues $191.6 $ 316.3 $ 464.1 $ 3.0 $ 975.0
====== ======== ======== ====== ========
Net income (loss) $ 72.8 $ 11.1 $ 47.8 $(16.7) $ 115.0
====== ======== ======== ====== ========
</TABLE>
65
<PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C>
Identifiable assets $301.8 $ 948.0 $2,813.9 $ 1.6 $4,065.3
Equity investments and advances 623.9 252.7 42.9 0.3 919.8
------ -------- -------- ------ --------
Total assets $925.7 $1,200.7 $2,856.8 $ 1.9 $4,985.1
====== ======== ======== ====== ========
1996
- ----
Electric & operating revenues $ 16.8 $ 245.1 $ 427.8 $ -- $ 689.7
Equity in income (loss) from
investments 153.3 3.0 2.0 (4.4) 153.9
------ -------- -------- ------ --------
Total operating revenues $170.1 $ 248.1 $ 429.8 $ (4.4) $ 843.6
====== ======== ======== ====== ========
Net income (loss) $ 68.2 $ 22.5 $ 28.8 $(27.4) $ 92.1
====== ======== ======== ====== ========
Identifiable assets $239.5 $1,512.7 $2,397.1 $ 87.3 $4,236.6
Equity investments and advances 709.2 141.3 30.8 34.6 915.9
------ -------- -------- ------ --------
Total assets $948.7 $1,654.0 $2,427.9 $121.9 $5,152.5
====== ======== ======== ====== ========
1995
- ----
Electric & operating revenues $ 13.9 $ 170.8 $ 146.8 $ -- $ 331.5
Equity in income (loss) from
investments 143.1 -- (2.7) (4.6) 135.8
------ -------- -------- ------ --------
Total operating revenues $157.0 $ 170.8 $ 144.1 $ (4.6) $ 467.3
====== ======== ======== ====== ========
Net income (loss) $ 57.0 $ 15.8 $ 7.9 $(16.7) $ 64.0
====== ======== ======== ====== ========
Identifiable assets $112.9 $1,302.7 $1,988.6 $ 89.0 $3,493.2
Equity investments and advances 729.4 69.0 31.8 50.6 880.8
------ -------- -------- ------ --------
Total assets $842.3 $1,371.7 $2,020.4 $139.6 $4,374.0
====== ======== ======== ====== ========
</TABLE>
(1) Includes corporate net interest expense and Mexico and Canada investments.
NOTE 16. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS PRODUCING
- ----------------------------------------------------------------------
ACTIVITIES (UNAUDITED)
- ----------------------
This section provides information required by SFAS No. 69, "Disclosures about
Oil and Gas Producing Activities." All of EME's oil and gas operations are
carried on by investees accounted for by the equity method. These investees all
follow the successful efforts method of accounting.
66
<PAGE>
EME's proportionate interest in net quantities of proved reserves at December
31, 1997, 1996 and 1995, and results of operations for the years then ended
related to equity method investees are shown in the following tables:
<TABLE>
<CAPTION>
Oil Natural Gas
Million of Barrels Billion of Cubic Feet
------------------ ---------------------
U.S. Canada Total U.S. Canada Total
<S> <C> <C> <C> <C> <C> <C> <C>
Proved developed and 1997 21.6 -- 21.6 189.3 -- 189.3
undeveloped reserves 1996 23.7 1.8 25.5 182.0 105.5 287.5
1995 23.1 2.0 25.1 180.6 118.5 299.1
<CAPTION>
U.S. Canada Total
<S> <C> <C> <C> <C>
Costs incurred in oil and 1997 $ 18.9 $ -- $ 18.9
gas property acquisition 1996 13.4 4.2 17.6
exploration, and 1995 37.2 6.5 43.7
development activities
Aggregate amounts of 1997 $194.9 $ -- $194.9
capitalized costs 1996 206.6 42.4 249.0
(including construction in 1995 202.1 46.6 248.7
progress) for proved and
unproved properties
Results of operations 1997 $ 39.2 $ -- $ 39.2
1996 39.2 (2.6) 36.6
1995 16.7 (2.5) 14.2
Standardized measure of 1997 $249.2 $ -- $249.2
discounted future net cash 1996 435.8 63.6 499.4
flows 1995 246.5 33.4 279.9
</TABLE>
In 1997, EME completed a sale of its ownership interest in B.C. Star Partners
which operated eleven producing properties in British Columbia, Canada. The
increase in 1996 in U.S. results of operations and total standardized measure
resulted primarily from higher oil and gas prices in 1996.
NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED)
- ----------------------------------------------
<TABLE>
<CAPTION>
1997 First(d) Second Third(d) Fourth(d) Total
-------- ----------- -------- --------- -------
<S> <C> <C> <C> <C> <C>
Operating revenues $285.0 $ 221.5/(c)/ $234.5 $234.0 $975.0
Income from operations 133.6 86.6 91.2 82.5 393.9
Net income 32.6 19.4/(a)//(b)/ 46.1 16.9 115.0
</TABLE>
67
<PAGE>
<TABLE>
<CAPTION>
1996 First(d) Second Third(d) Fourth(d)(f) Total
------- ------ ------- ----------- -----
<S> <C> <C> <C> <C> <C>
Operating revenues $190.7 $184.3 $212.0 $256.6 $843.6
Income from operations 85.2 73.3 107.5 101.1 367.1
Net income 22.0 31.0/(e)/ 31.0 8.1 92.1
</TABLE>
(a) Includes a $14 million gain on sale of ownership interest in an oil and gas
investment.
(b) Includes a $13.1 million extraordinary loss on early extinguishment of
debt.
(c) Decline in revenues as a result of restructuring agreements associated with
the 49% acquisition of Loy Yang B in May 1997.
(d) Reflects EME's seasonal pattern, in which the majority of earnings from
domestic projects are recorded in the third quarter of each year and higher
electric revenues from certain international projects are recorded during
the winter months of each year.
(e) Includes a $15.5 million gain on the sale of four operating geothermal
facilities.
(f) Includes operating revenues and income for Loy Yang B Unit 2 and the
Kwinana project which both commenced operations in the fourth quarter of
1996.
68
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
POSITIONS WITH EME
The following table sets forth the names and ages of, the positions held with
EME by, and the terms of office of, the directors and executive officers of EME
as of March 1, 1998.
<TABLE>
<CAPTION>
DIRECTOR POSITION HELD
CONTINUOUSLY TERM CONTINUOUSLY TERM
NAME, POSITION AND AGE SINCE EXPIRES SINCE EXPIRES
- ---------------------- ------------ ------- ------------- -------
<S> <C> <C> <C> <C>
Alan J. Fohrer, 47................................................................ 1992 1998 -- --
Chairman of the Board
Bryant C. Danner, 60.............................................................. 1993 1998 -- --
Director
Robert M. Edgell, 51.............................................................. 1993 1998 1988 1998
Director, Executive Vice President and
Division President of EME, Asia Pacific
Edward R. Muller, 45.............................................................. 1993 1998 1993 1998
Director, President and Chief Executive Officer
S. Linn Williams, 51.............................................................. -- -- 1994 1998
Senior Vice President and General Counsel
Terry V. Charlton, 51............................................................. -- -- 1997 1998
Senior Vice President and Division President of EME, Europe,
Central Asia, Middle East and Africa
James V. Iaco, Jr., 53............................................................ -- -- 1994 1998
Senior Vice President and Chief Financial Officer
Division President of EME, Americas
Georgia R. Nelson, 48............................................................. -- -- 1996 1998
Senior Vice President, Worldwide Operations
</TABLE>
BUSINESS EXPERIENCE
Set forth below is a description of the principal business experience during
the past five years of each of the individuals named above and the name of each
public company in which any director named above is a director.
MR. FOHRER has been Chairman of the Board of EME since January 30, 1998. From
1993 to 1998, Mr. Fohrer served as Vice Chairman of the Board. Mr. Fohrer has
been Executive Vice President and Chief Financial Officer of Edison
International and SCE since June 1995. Effective February 1996 and June 1995,
Mr. Fohrer also served as Treasurer of SCE and Edison International,
respectively, until August 1996. Mr. Fohrer was Senior Vice President,
Treasurer and Chief Financial Officer of Edison International, and Senior Vice
President and Chief Financial Officer of SCE from January 1993 until May 1995.
Mr. Fohrer was interim Chief Executive Officer of EME between May 1993 and
August 1993. From 1991 until 1993, Mr. Fohrer was Vice President, Treasurer and
Chief Financial Officer of Edison International and SCE.
MR. DANNER has been Executive Vice President and General Counsel of Edison
International and SCE since June 1995. Mr. Danner was Senior Vice President and
General Counsel of Edison International and SCE from July 1992 until May 1995.
69
<PAGE>
MR. EDGELL has been Executive Vice President of EME since april 1988. Mr.
Edgell was named Division President of EME'S Asia Pacific region in January
1995.
MR. MULLER has been President and Chief Executive Officer of EME since August
1993. Prior to joining EME, Mr. Muller served as vice president, chief
administrative officer, general counsel and secretary of Whittaker Corporation,
an aerospace firm, from 1988 until 1992 and as vice president, chief financial
officer, general counsel and secretary of Whittaker Corporation from 1992 until
1993. from 1991 until 1993, Mr. Muller also served as vice president, secretary
and general counsel of BioWhittaker, Inc., a biotechnology company. Mr. Muller
is a director of Whittaker Corporation, Oasis Residential, Inc. and Global
Marine Inc.
MR. WILLIAMS has been Senior Vice President and General Counsel of EME since
November 1994. From 1985 through 1989 and 1992-1993, Mr. Williams was a partner
with the law firm of Gibson, Dunn and Crutcher. From 1993-1994, Mr. Williams
was a partner with the law firm of Jones, Day, Reavis and Pogue.
MR. CHARLTON has been Senior Vice President and Division President, Europe,
Central Asia, Middle East and Africa since September 8, 1997. Prior to joining
EME, Mr. Charlton worked as a consultant for EME. Mr. Charlton served as Group
General Manager - Water, Oil and Gas Industries Group for Tubemakers of
Australia Limited from 1993 until 1996.
MR. IACO has been Senior Vice President and Chief Financial Officer of EME
since January 1994 and Division President of EME's Americas region since January
26, 1998. From September 1993 until December 1993, Mr. Iaco was self-employed
and provided consulting services, specializing in restructuring, finance, crisis
management and other management services. From October 1992 until September
1993, Mr. Iaco served as senior vice president and chief financial officer of
Phoenix Distributors, Inc., a distributor of industrial gas and welding
supplies.
MS. NELSON has been Senior Vice President, Worldwide Operations since January
1996. Ms. Nelson was Division President of EME's Americas region from January
1996 to January 26, 1998. Prior to joining EME, Ms. Nelson served as Senior
Vice President of SCE from June 1995 until December 1995 and Vice President of
SCE from March 1993 until June 1995. From 1992 to 1993, Ms. Nelson served as a
Special Assistant to the Chairman of Edison International. Ms. Nelson is a
director of CalMat Company.
70
<PAGE>
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table provides information concerning compensation paid by EME
to each of the named executive officers during the years 1997, 1996 and 1995 for
services rendered by such persons in all capacities to EME and its subsidiaries.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
COMPENSATION
ANNUAL COMPENSATION AWARDS
----------------------------------------- -------------
OTHER ANNUAL SECURITIES ALL OTHER
SALARY BONUS COMPENSATION UNDERLYING COMPENSATION
NAME AND PRINCIPAL POSITION YEAR ($) ($) ($) OPTIONS (#)(2) ($)(3)
- ---------------------------------------- ---- ------- ------- ------------- -------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Edward R. Muller 1997 400,000 456,000 3,478 33,300 28,587
President and Chief Executive Officer 1996 370,000 444,000 2,621 41,000 23,148
1995 335,000 331,700 2,646 53,190 17,521
Robert M. Edgell 1997 317,000 325,000 -- 23,300 33,600(4)
Executive Vice President 1996 292,000 275,000 133 25,700 88,071(4)
1995 252,000 250,000 700 30,770 8,492
S. Linn Williams 1997 300,000 240,000 1,643 15,400 18,568
Senior Vice President 1996 275,000 220,000 734 20,100 13,148
and General Counsel 1995 250,000 180,000 1,028 24,390 141
Georgia R. Nelson (1) 1997 290,000 206,000 7,125 15,400 17,829
Senior Vice President, Worldwide 1996 270,000 190,000 1,337 23,700 14,446
Operations
James V. Iaco, Jr. 1997 280,000 224,000 4,913 15,400 14,962
Senior Vice President and Chief 1996 250,000 200,000 2,906 19,800 10,416
Financial Officer 1995 190,000 140,000 2,223 19,710 0
</TABLE>
(1) Ms. Nelson was appointed Senior Vice President, Operations and Division
President of EME, Americas in January 1996.
(2) No Stock Appreciation Rights (SARs) were granted. Amounts shown are
comprised of Edison International nonqualified stock options and EME
"phantom stock" options. For 1997, Mr. Muller, Mr. Edgell, Mr. Williams, Ms.
Nelson and Mr. Iaco received 10,500; 7,500; 5,500; 5,500 ; and 5,500 Edison
International stock options, respectively; and 22,800; 15,800; 9,900; 9,900;
and 9,900 EME phantom stock options, respectively. For 1996, Mr. Muller, Mr.
Edgell, Mr. Williams, Ms. Nelson and Mr. Iaco received 10,200; 6,600; 5,400;
9,000; and 5,100 Edison International stock options, respectively; and
30,800; 19,100; 14,700; 14,700; and 14,700 EME phantom stock options,
respectively. For 1995, Mr. Muller, Mr. Edgell, Mr. Williams and Mr. Iaco
received 10,000; 5,200; 4,500; and 3,800 Edison International stock options,
respectively; and 43,190; 25,570; 19,890; and 15,910 EME phantom stock
options, respectively. Each Edison International nonqualified stock option
gives the named
71
<PAGE>
executive officer the right to purchase one share of Edison International
Common Stock, and each EME phantom stock option may be exercised to realize
any appreciation in the value of one hypothetical share of EME stock over
annually escalated exercise prices, on the terms described in the notes to
the Option Grants in the 1997 Option Grant Table below.
(3) Includes the following company contributions to a defined contribution plan,
Stock Savings Plus Plan (SSPP) and a supplemental plan for eligible
participants who are affected by SSPP participation limits imposed on
higher-paid individuals by federal tax law: For 1997, Mr. Muller, $25,305;
Mr. Edgell $13,000; Mr. Williams, $15,599; Ms. Nelson, $14,384; and Mr.
Iaco, $14,376. For 1996, Mr. Muller, $11,455; Mr. Edgell, $4,500; Mr.
Williams, $6,301; Ms. Nelson, $7,913; and Mr. Iaco, $6,077. For 1995, Mr.
Muller, $15,988; Mr. Edgell, $8,220; Mr. Williams, $0; and Mr. Iaco, $0.
Also includes the following amounts of interest accrued on deferred
compensation of the named individuals, which is considered under the rules
of the Securities and Exchange Commission to be at an above-market rate: For
1997, Mr. Muller, $3,283; Mr. Edgell, $458; Mr. Williams, $2,969; Ms.
Nelson, $3,445; and Mr. Iaco, $586. For 1996, Mr. Muller, $1,508; Mr.
Edgell, $239; Mr. Williams, $926; Ms. Nelson, $1,882; and Mr. Iaco, $139.
For 1995, Mr. Muller, $1,533; Mr. Edgell $272; Mr. Williams, $141; and Mr.
Iaco, $0.
(4) Includes an overseas service allowance of $20,142 and $75,832 in 1997 and
1996, respectively. For each employee serving in an overseas site, the
allowance calculation depends on base pay, family size and location.
EXECUTIVE STOCK OPTIONS
The following table sets forth certain information concerning Edison
International stock options and EME phantom stock options granted pursuant to
the Edison International Officer's Long-Term Incentive Compensation Plan (LTIP)
to the executive officers named in the Summary Compensation Table above during
1997.
<TABLE>
<CAPTION>
OPTION GRANTS IN 1997(1)
Individual Grants
----------------------------------------------------------
Exercise
Options Percent of Total or Base Grant Date
Granted Options Granted to Price Expiration Present
Name (#) Employees in 1997 ($/Sh) Date Value ($)
---- ------- ------------------ -------- ---------- ---------
(2)(3) (4)(5) (6)
<S> <C> <C> <C> <C> <C>
Edward R. Muller
Edison International 10,500 17% 19.75 01/02/2007 61,005
EME 22,800 10% 120.55 01/02/2007 230,964
Robert M. Edgell
Edison International 7,500 12% 19.75 01/02/2007 43,575
EME 15,800 7% 120.55 01/02/2007 160,054
S. Linn Williams
Edison International 5,500 9% 19.75 01/02/2007 31,955
EME 9,900 4% 120.55 01/02/2007 100,287
Georgia R. Nelson
Edison International 5,500 9% 19.75 01/02/2007 31,955
EME 9,900 4% 120.55 01/02/2007 100,287
James V. Iaco, Jr.
Edison International 5,500 9% 19.75 01/02/2007 31,955
EME 9,900 4% 120.55 01/02/2007 100,287
</TABLE>
72
<PAGE>
(1) No SARs were granted. This table reflects all awards made under the LTIP
("LTIP Options") during 1997. In addition to Edison International stock
options, it includes EME "phantom stock" options.
(2) Each Edison International nonqualified stock option represents the right to
purchase one share of common stock of Edison International. The Edison
International stock options include dividend equivalents equal to the
dividends that would have been paid on an equal number of shares of Edison
International Common Stock. Dividend equivalents will be credited following
the first three years of the option term if certain Edison International
performance criteria discussed below are met. Dividend equivalents
accumulate without interest. Once earned and vested, the dividend
equivalents are payable in cash (i) upon the request of the holder prior to
the final year of the option term, (ii) upon the exercise of the related
option, or (iii) at the end of the option term regardless of whether the
related option is exercised. After such payment, however, no additional
dividend equivalents will accrue on the related option.
The dividend equivalent performance criteria is measured by Edison
International Common Stock total shareholder return. If the average
quarterly percentile ranking is less than the 60th percentile of that of the
companies comprising the Dow Jones Electric Utilities Group Index, the
dividend equivalents are reduced; if the Edison International total
shareholder return ranking is less than the 25th percentile, the dividend
equivalents are canceled. For rankings between the 60th and 25th
percentiles, the dividend equivalents are prorated. The total shareholder
return is measured at the end of the initial three-year period and will set
the percentage payable for the entire term. If less than 100% of the
dividend equivalents are earned, the unearned portion may be restored later
in the option term if Edison International's cumulative total shareholder
return ranking for the option term attains at least the 60th percentile.
(3) Each EME phantom stock option represents a right to exercise an option to
realize any appreciation in the value of one hypothetical share of EME
stock. The value of the stock is determined by a formula linked to project
values, which are determined annually, and is based on 10 million total
shares. Project values are determined based on economic models whose
assumptions have been approved by Edison International Phantom Plan
Management and Valuation Committees. The valuation is consistent with the
bases on which EME invests, acquires, finances, refinances and otherwise
makes capital decisions for new investments and value-maximizing decisions
for existing investments. The exercise price is initially set equal to the
value of the stock on the date of grant escalated on a compound basis (12%
per year) thereafter by a factor reflecting the approximate cost of capital
during the year as determined by the Compensation and Executive Personnel
Committee (CEP Committee) of Edison International. The annual escalation
factor will be adjusted prospectively by the CEP Committee for significant
changes in the cost of capital. If the value of a share of EME stock
exceeds the exercise price for any subsequent year, the executive may
exercise his option right with respect to any portion of his vested units
during the 60-day exercise window in the second quarter of the following
year and be paid in cash the difference between the exercise price and the
value of the shares.
(4) The LTIP Options become exercisable in three equal installments beginning on
the first anniversary of their date of grant. Each option has a term of 10
years, subject to earlier expiration upon termination of employment as
described below. The options are not transferable except upon death.
Effective January 1, 1998, outstanding LTIP Options were amended to allow
certain senior officers to transfer LTIP Options to a spouse, child or
grandchild. If an executive retires, dies, or is permanently and totally
disabled during the three-year vesting period, the unvested LTIP Options
will vest and be exercisable to the extent of 1/36 of the grant for each
full month of service during the vesting period. Unvested LTIP Options of
any person who has served in the past on the Edison International or SCE
Management Committee will vest and be exercisable upon the member's
retirement, death, or permanent and total disability. None of the named
officers have served on either of the two committees. Upon retirement,
death or permanent and total disability, the vested LTIP Options may
continue to be exercised within their original term by the recipient or
beneficiary. If an executive is terminated other than by retirement, death
or permanent and total disability, LTIP Options which had vested as of the
prior anniversary date of the grant are forfeited unless exercised within
180 days of the
73
<PAGE>
date of termination in the case of Edison International options, or during
the next 60-day exercise window in the case of EME phantom stock options.
All unvested LTIP Options are forfeited on the date of termination.
Appropriate and proportionate adjustments may be made by the Edison
International CEP Committee to outstanding Edison International stock
options to reflect any impact resulting from various corporate events such
as reorganizations, stock splits and so forth. If Edison International is
not the surviving corporation in such a reorganization, all LTIP Options
then outstanding will become vested and be exercisable unless provisions are
made as part of the transaction to continue the LTIP or to assume or
substitute stock options of the successor corporation with appropriate
adjustments as to the number and price of the options. The Edison
International CEP Committee administers the LTIP and has sole discretion to
determine all terms and conditions of any grant, subject to plan limits. It
may substitute cash equivalent in value to the LTIP Options and, with the
consent of the executive, may amend the terms of any award agreement,
including the price of any option, the post-termination term, and the
vesting schedule.
(5) The expiration date of the LTIP Options is January 2, 2007; however, the
final 60-day exercise period of EME phantom stock options will occur during
the second quarter of that year. The LTIP Options are subject to earlier
expiration upon termination of employment as described in footnote (4)
above.
(6) The grant date present value of each Edison International stock option was
calculated as the sum of (i) the option value and (ii) the dividend
equivalent value. The option value was calculated to be approximately $2.56
per option share using the Black-Scholes stock option pricing model. For
purposes of this calculation, it was assumed that options would be
outstanding for an average of seven years prior to exercise, the volatility
rate was assumed to be 17%, the risk-free rate of return was assumed to be
6.45%, the historic average dividend yield was assumed to be 5.89% and the
stock price and exercise price were $19.75.
The dividend equivalent value of each Edison International stock option
granted in 1997 was calculated to be $3.25. The grant date value of the
dividend equivalent rights included with respect to each Edison
International stock option was determined by (i) adding the dividends
(without reinvestment) that would be received on a number of shares of
Edison International common stock equal to the number of shares subject to
the option for a period of seven years from the date on which the option was
granted, based on the annual dividend rate at grant of $1.00 per share and
(ii) discounting that amount to its present value assuming a discount rate
of 11.6%, which was Edison's authorized return on common equity in 1997.
This calculation does not reflect any reduction in value for the risk that
Edison International performance measures may not be met.
The value of an EME option was calculated to be $10.13 using the Black-
Scholes stock option pricing model assuming an average exercise period of
seven years, a volatility rate of 19.22%, a risk-free rate of return of
6.37%, a dividend yield of 0% and an exercise price of $266.50. These
assumptions are based on average values of a group of peer companies
adjusted for differences in capital structure.
The actual value that an executive may realize will depend on various
factors on the date the option is exercised, so there is no assurance the
value realized by an executive will be at or near the grant date value
estimated by the Black-Scholes model. The estimated values under that model
are based on certain assumptions and are not a prediction as to future stock
price.
74
<PAGE>
The following table sets forth certain information with respect to the
exercise during 1997 by the executive officers named in the Summary Compensation
Table above of options to purchase shares of common stock of Edison
International and exercise hypothetical shares of stock of EME and option values
as of December 31, 1997.
AGGREGATED OPTION EXERCISES IN 1997
AND YEAR-END OPTION VALUES
<TABLE>
<CAPTION>
NUMBER OF VALUE OF UNEXERCISED
UNEXERCISED OPTIONS AT IN-THE-MONEY OPTIONS AT
FISCAL YEAR-END (#) FISCAL YEAR-END ($)(1)
---------------------- -----------------------
SHARES ACQUIRED ON EXERCISABLE/ EXERCISABLE/
NAME EXERCISE (#) VALUE REALIZED ($) UNEXERCISABLE UNEXERCISABLE
- ---- ------------------ ------------------ ------------- -------------
<S> <C> <C> <C> <C>
Edward R. Muller
Edison International -- -- 44,167/20,633 270,383/185,198
EME -- -- 56,880/57,730 2,688,213/1,487,610
Robert M. Edgell
Edison International -- -- 41,717/13,633 286,876/119,735
EME -- -- 34,634/37,056 1,630,303/900,457
S. Linn Williams
Edison International -- -- 4,800/10,600 55,088/94,269
EME -- -- 18,160/26,330 889,867/696,864
Georgia R. Nelson
Edison International 38,600 193,165(2) 4,800/22,300 21,975/234,631
EME -- -- 4,900/19,700 167,954/335,908
James V. Iaco, Jr.
Edison International 6,534 35,835(3) 0/10,166 0/89,402
EME -- -- 22,547/25,003 1,049,102/624,618
</TABLE>
(1) Edison International options are treated as "in-the-money" if the fair
market value of the underlying shares at December 31, 1997, exceeded the
exercise price of the options. The dollar amounts shown for Edison
International options are the differences between (i) the fair market value
of the Edison International Common Stock underlying all unexercised "in-the-
money" options at year-end 1997 and (ii) the exercise prices of those
options. The aggregate value at year-end 1997 of all accrued dividend
equivalents, exercisable and unexercisable, for Mr. Muller, Mr. Edgell, Mr.
Williams, Ms. Nelson and Mr. Iaco was $144,572/$0, $248,882/$0, $0/$0,
$30,288/$0 and $0/$0, respectively.
EME phantom stock options are considered "in-the-money" if the value of EME
phantom stock, which is determined annually by a formula linked to project
values, exceeds prescribed exercise prices. The value at year-end is not
available until the second quarter of the following year. Therefore, amounts
shown reflect the value at fiscal year-end for 1996, the most recent data
available.
(2) Includes $27,790 of value realized from dividend equivalents.
(3) Includes $4,565 of value realized from dividend equivalents.
75
<PAGE>
RETIREMENT BENEFITS
- -------------------
The following table sets forth estimated gross annual benefits payable upon
retirement at age 65 to the executive officers named in the Summary Compensation
Table above in the remuneration and years of service classifications indicated.
PENSION PLAN TABLE(1)
<TABLE>
<CAPTION>
YEARS OF SERVICE
--------------------------------------------------------------------------
REMUNERATION 10 15 20 25 30 35 40
- --------------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
$ 100,000 $ 25,000 $ 33,750 $ 42,500 $ 51,250 $ 60,000 $ 65,000 $ 70,000
150,000 37,500 50,625 63,750 76,875 90,000 97,500 105,000
200,000 50,000 67,500 85,000 102,500 120,000 130,000 140,000
250,000 62,500 84,375 106,250 128,125 150,000 162,500 175,000
300,000 75,000 101,250 127,500 153,750 180,000 195,000 210,000
350,000 87,500 118,125 148,750 179,375 210,000 227,500 245,000
400,000 100,000 135,000 170,000 205,000 240,000 260,000 280,000
450,000 112,500 151,875 191,250 230,625 270,000 292,500 315,000
500,000 125,000 168,750 212,500 256,250 300,000 325,000 350,000
550,000 137,500 185,625 233,750 281,875 330,000 357,500 385,000
600,000 150,000 202,500 255,000 307,500 360,000 390,000 420,000
</TABLE>
(1) Estimates are based on the provisions of the retirement plan (the
"Retirement Plan"), a qualified defined benefit employee retirement plan,
currently covering EME's executive officers with the following assumptions:
(i) the present Retirement Plan will be maintained, (ii) optional forms of
payment that reduce benefit amounts have not been selected, and (iii) any
benefits in excess of limits contained in the Internal Revenue Code of 1986
(the "Code") and any incremental retirement benefits attributable to
consideration of the annual bonus or participation in EME's deferred
compensation plans will be paid out of the general assets of EME under a
nonqualified supplemental executive retirement plan (an "ERP"). Amounts in
the Pension Plan Table include neither the Income Continuation Plan nor the
Survivor Income/Retirement Income plans, which provide postretirement death
benefits and supplemental retirement income benefits. These plans are
discussed in "Other Retirement Benefits".
The Retirement Plan and ERP provide monthly benefits at normal retirement age
(65 years) based on a unit benefit for each year of service plus a benefit
determined by a percentage ("Service Percentage") of the executive's average
highest 36 consecutive months of regular salary and, in the case of the ERP, the
average highest three bonuses in the last five years prior to attaining age 65.
Compensation used to calculate combined benefits under the Retirement Plan and
ERP is based on base salary and bonus as reported in the Summary Compensation
Table. The Service Percentage is based on 1-3/4% per year for the first 30
years of service (52-1/2% upon completion of 30 years' service) and 1% for each
year in excess of 30. The actual benefit determined by the Service Percentage
would take into account the unit benefit and be offset by up to 40% of the
executive's primary Social Security benefits.
The normal form of benefit is a life annuity with a 50% survivor benefit
following the death of the participant. Retirement benefits are reduced for
retirement prior to age 61. The amounts shown in the
76
<PAGE>
Pension Plan Table above do not reflect reductions in retirement benefits due to
the Social Security offset or early retirement.
Mr. Edgell has elected to retain coverage under a previous benefit program.
This program provided, among other benefits, the post-retirement benefits
discussed in the following section. The ERP benefits provided in the previous
program are less than the benefits shown in the Pension Plan Table. To determine
these reduced benefits, multiply the dollar amounts shown in each column by the
following factors: 10 years of service -- 70%, 15 years -- 78%, 20 years --
82%, 25 years -- 85%, 30 years -- 88%, 35 years -- 88%, and 40 years -- 89%.
At December 31, 1997, Mr. Muller had completed 4 years of service; Mr.
Edgell, 27 years; Mr. Williams, 3 years; Ms. Nelson, 27 years; Mr. Iaco, 3
years.
OTHER RETIREMENT BENEFITS
Additional post-retirement benefits are provided pursuant to the Survivor
Income Continuation Plan and the Survivor Income/Retirement Income Plan under
the Executive Supplemental Benefit Program.
The Survivor Income Continuation Plan provides a post-retirement survivor
benefit payable to the beneficiary of the executive officer following his or her
death. The benefit is approximately 24% of final compensation (salary at
retirement and the average of the three highest bonuses paid in the five years
prior to retirement) payable for ten years certain. If a named executive
officer's final annual compensation were $600,000 (the highest compensation
level in the Pension Plan Table above), the beneficiary's estimated annual
survivor benefit would be approximately $144,000. Mr. Edgell has elected
coverage under this program.
The Supplemental Survivor Income/Retirement Income Plan provides a post-
retirement survivor benefit payable to the beneficiary of the executive officer
following his or her death. The benefit is 25% of final compensation (salary at
retirement and the average of the three highest bonuses paid in the five years
prior to retirement) payable for ten years certain. At retirement, an executive
officer has the right to elect the retirement income benefit in lieu of the
survivor income benefit. The retirement income benefit is 10% of final
compensation (salary at retirement and the average of the three highest bonuses
paid in the five years prior to retirement) payable to the executive officer for
ten years certain immediately following retirement. If a named executive
officer's final annual compensation were $600,000 (the highest compensation
level in the Pension Plan Table above), the beneficiary's estimated annual
survivor benefit would be approximately $150,000. If a named executive officer
were to elect the retirement income benefit in lieu of survivor income and had
final annual compensation of approximately $600,000 (the highest compensation
level in the Pension Plan Table above), the named executive officer's estimated
annual benefit would be approximately $60,000. Mr. Edgell has elected coverage
under this program.
The 1985 Deferred Compensation Plan provides a post-retirement survivor
benefit. This plan allowed eligible participants in September 1985 to elect
voluntarily to defer until retirement a portion of annual salary and annual
bonuses otherwise earned and payable for the period October 1985 through January
1990. The post-retirement survivor benefit is 50% of the annual deferred
compensation payable from the participant's account. Survivor benefit payments
begin following completion of the participant's deferred compensation payments.
If the named beneficiary is the executive's spouse, then survivor benefits are
paid as a life annuity, five years certain; the benefit amount will be reduced
actuarially if the
77
<PAGE>
spouse is more than five years younger than the executive at the time of the
executive's death. If the beneficiary is not the spouse, then benefits are paid
for five years only.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
CERTAIN BENEFICIAL OWNERS
- --------------------------
Set forth below is certain information regarding each person who is known
to EME to be the beneficial owner of more than five percent of EME's common
stock.
<TABLE>
<CAPTION>
Title of Class Name and Amount and Percent of
-------------- Address of Nature of Class
Beneficial Beneficial ------------
Owner Ownership
---------- ----------
<S> <C> <C> <C>
Common Stock, no par value The Mission 100 shares 100%
Group held directly
18101 Von and with
Karman Avenue, exclusive
Suite 1700 voting and
Irvine, investment
California power
92612
</TABLE>
MANAGEMENT
- ----------
Set forth below is certain information about the beneficial ownership in
equity securities of Edison International by all directors of EME, the executive
owners of EME named in the Summary Compensation Table in Item 6 and all
directors and executive officers of EME as a group.
<TABLE>
<CAPTION>
Amount and Nature of
Beneficial Ownership
as of
Company and December 31,
Name Class of Stock 1997(a)(b)(c)(d)(e)
- ----- --------------------- ------------------------------
<S> <C> <C>
John E. Bryson Edison International
Common Stock 504,128(f)
Alan J. Fohrer Edison International
Common Stock 143,239
Bryant C. Danner Edison International
Common Stock 140,030
Robert M. Edgell Edison International
Common Stock 62,877
Edward R. Muller Edison International
Common Stock 56,200
Mission Capital
Preferred Securities 2,198
S. Linn Williams Edison International
Common Stock 9,998
Georgia R. Nelson Edison International
Common Stock 35,187
James V. Iaco, Jr. Edison International
Common Stock 4,800
Mission Capital
Preferred Securities 1,700
All directors and Edison International
executive officers as Common Stock 956,459
a group Mission Capital
Preferred Securities 3,898
</TABLE>
(a) Unless otherwise indicated, each named person has voting and investment
power over the listed shares and such voting and investment power is
exercised solely by the named person or shared with a spouse. No named
person or group owns more than 1% of the outstanding shares of the class.
(b) Includes the following number of Edison International shares owned under the
SSPP: Mr. Bryson, 14,127 shares; Mr. Fohrer, 12,238 shares; Mr. Danner,
1,829 shares; Mr. Edgell, 14,727 shares; Mr. Muller, 0 shares; Mr. Williams,
64 shares; Ms. Nelson, 14,753 shares; Mr. Iaco, 0 shares; and all directors
and executive officers as a group, 57,738 shares. Each such person and
group may be deemed to share voting power with the trustee appointed under
the SSPP.
(c) Includes the following number of Edison International shares with respect to
which the right exists to acquire beneficial ownership within 60 days
through the exercise of options granted under an employee benefit plan
78
<PAGE>
known as the 1987 Long-Term Incentive Compensation Plan as amended and
restated by the Edison International Officer Long-Term Incentive
Compensation Plan effective April 16, 1992: Mr. Bryson, 477,801 shares; Mr.
Fohrer, 130,501 shares; Mr. Danner, 136,201 shares; Mr. Edgell, 48,150
shares; Mr. Muller, 54,400 shares; Mr. Williams, 9,934 shares; Ms. Nelson,
20,434 shares; Mr. Iaco, 4,800 shares; and all directors and executive
officers as a group, 882,221 shares.
(d) Includes Edison International shares held in own name by Mr. Fohrer, 500
shares; spouse's name by Mr Bryson, 200 shares; held with another person by
Mr. Bryson, 6,000 shares; held as trustee by Mr. Bryson, 6,000 shares; held
as custodian by Mr. Muller, 400 shares; and held in broker's name by Mr.
Danner, 2,000 shares, and Mr. Muller, 1,400 shares.
(e) Includes the following number of shares of Monthly Income Preferred
Securities of Mission Capital, a limited partnership of which EME is the
sole general partner: Mr. Muller, 280 shares held in spouse's name, 390
shares held in custodial names and 8 shares held as co-trustee of trust with
shared voting and investment power; Mr. Iaco, 750 shares held in spouse's
name; all directors and executive officers as a group, 1,030 shares held in
spouses' names and 390 shares held in custodial names.
(f) Mr. Bryson retired as Chairman of EME's Board effective January 30, 1998.
SECTION 16 (a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
- --------------------------------------------------------
Pursuant to Item 405 of Regulation S-K, EME is required to disclose the
following recently elected officers who each had one delinquent Form 3 "Initial
Statement of Beneficial Ownership of Securities" filing which is required to be
filed within 10 days of being elected for fiscal year 1997:
NAME DATE ELECTED
---- ------------
Cynthia S. Dubin, Vice President July 15, 1997
Edward J. Kania, Vice President July 15, 1997
William P. von Blasingame, Vice President July 15, 1997
Stephen P. Barrett, Vice President July 15, 1997
Michael P. Childers, Vice President December 1, 1997
Steven R. Schuler, Vice President December 16, 1997
79
<PAGE>
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In April 1994, EME made a loan to S. Daniel Melita, Vice President of EME, in
the amount of $150,000 in exchange for a note executed by Mr. Melita and payable
to EME at seven percent (7%) annual interest. The entire note, together with
accrued interest, was paid in December 1996. The largest aggregate amount of
indebtedness outstanding under the loan during 1996 was $171,000.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) LIST OF FINANCIAL STATEMENTS
See Index to Consolidated Financial Statements at Item 8 of this report.
(2) LIST OF FINANCIAL STATEMENT SCHEDULES
The following item is filed as a part of this report pursuant to Item 14(d) of
Form 10-K:
The Cogeneration Group Combined Financial Statements as of December 31, 1997,
1996 and 1995.
Schedules pursuant to Item 8 of Form 10-K are omitted because the required
information is either presented in the financial statements or notes thereto, or
is not applicable, required or material.
(3) LIST OF EXHIBITS
(a)
EXHIBIT NO. DESCRIPTION
- ----------- -----------
2.1 Agreement for the sale and purchase of shares in First Hydro
Limited, dated December 21, 1995 between PSB Holding Limited and
First Hydro Finance Plc, incorporated by reference to Exhibit 2.1
to EME's Current Report on Form 8-K, No. 1-13434 dated January 4,
1996.
2.2 Transaction Implementation Agreement, dated March 29, 1997 between
The State Electricity Commission of Victoria, Edison Mission
Energy Australia Limited, Loy Yang B Power Station Pty Ltd, Loy
Yang Power Limited, The Honourable Alan Robert Stockdale, Leanne
Power Pty Ltd and EME, incorporated by reference to Exhibit 2.2 to
EME's Current Report on Form 8-K, No. 1-13434 dated May 22, 1997.
3.1 Amended and Restated Articles of Incorporation of EME incorporated
by reference to Exhibit 3.1 to EME's Current Report on Form 8-K,
No. 1-13434 dated January 30, 1996. Originally filed with EME's
Registration Statement on Form 10 to the Securities and Exchange
Commission on September 30, 1994 and amended by Amendment No. 1
thereto dated November 19, 1994 and Amendment No. 2 thereto dated
November 21, 1994 (as so amended, the "Form 10").
3.2 By-Laws of EME, incorporated by reference to Exhibit 3.2 to EME's
Form 10.
4.1 Copy of the Global Debenture representing EME's 9-7/8% Junior
Subordinated Deferrable Interest Debentures, Series A, Due 2024.
80
<PAGE>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
4.2 Conformed copy of the Indenture dated as of November 30, 1994
between EME and The First National Bank of Chicago, as trustee.
4.2.1 First Supplemental Indenture dated as of November 30, 1994 to
Indenture dated as of November 30, 1994 between EME and The First
National Bank of Chicago, as trustee.
10.2 Power Purchase Contract between Southern California Edison Company
and Champlin Petroleum Company, dated March 8, 1985, incorporated
by reference to Exhibit 10.2 to EME's Form 10.
10.2.1 Amendment to Power Purchase Contract between Southern California
Edison Company and Champlin Petroleum Company, dated July 29,
1985, incorporated by reference to Exhibit 10.2.1 to EME's Form
10.
10.2.2 Amendment No. 2 to Power Purchase Contract between Southern
California Edison Company and Champlin Petroleum Company, dated
October 29, 1985, incorporated by reference to Exhibit 10.2.2 to
EME's Form 10.
10.4 Power Purchase Contract between Southern California Edison Company
and Imperial Energy Company, dated February 22, 1984, incorporated
by reference to Exhibit 10.4 to EME's Form 10.
10.4.1 Amendment to Power Purchase Contract between Southern California
Edison Company and Imperial Energy Company, dated November 13,
1984, incorporated by reference to Exhibit 10.4.1 to EME's Form
10.
10.6 Power Purchase Contract between Southern California Edison Company
and Imperial Energy Company Niland No. 2, dated April 16, 1985,
incorporated by reference to Exhibit 10.6 to EME's Form 10.
10.7 Power Purchase Contract between Southern California Edison Company
and Chevron U.S.A. Inc., dated November 9, 1984, incorporated by
reference to Exhibit 10.7 to EME's Form 10.
10.7.1 Amendment No. 1 to Power Purchase Contract between Southern
California Edison Company and Chevron U.S.A. Inc., dated March 29,
1985, incorporated by reference to Exhibit 10.7.1 to EME's Form
10.
10.7.2 Amendment No. 2 to Power Purchase Contract between Southern
California Edison Company and Chevron U.S.A. Inc., dated November
21, 1985, incorporated by reference to Exhibit 10.7.2 to EME's
Form 10.
10.7.3 Amendment No. 3 to Power Purchase Contract between Southern
California Edison Company and Chevron U.S.A. Inc., dated November
21, 1985, incorporated by reference to Exhibit 10.7.3 to EME's
Form 10.
10.8 Power Purchase Contract between Southern California Edison Company
and Arco Petroleum Products Company (Watson Refinery),
incorporated by reference to Exhibit 10.8 to EME's Form 10.
10.9 Power Supply Agreement between State Electricity Commission of
Victoria, Loy Yang B Power Station Pty. Ltd. and the Company
Australia Pty. Ltd., as managing partner of the Latrobe Power
Partnership, dated December 31, 1992, incorporated by reference to
Exhibit 10.9 to EME's Form 10.
10.10 Power Purchase Agreement between P.T. Paiton Energy Company as
Seller and Perusahaan Umum Listrik Negara as Buyer, dated February
12, 1994, incorporated by reference to Exhibit 10.10 to EME's Form
10.
10.11 Amended and Restated Power Purchase Contract between Southern
California Energy Company and Midway-Sunset Cogeneration Company,
dated May 5, 1988, incorporated by reference to Exhibit 10.11 to
EME's Form 10.
81
<PAGE>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
10.12 Parallel Generation Agreement between Kern River Cogeneration
Company and Southern California Energy Company, dated January 6,
1984, incorporated by reference to Exhibit 10.12 to EME's Form 10.
10.13 Parallel Generation Agreement between Kern River Cogeneration
(Sycamore Project) Company and Southern California Energy Company,
dated December 18, 1984, incorporated by reference to Exhibit
10.13 to EME's Form 10.
10.14 Amendment No. 2 to Power Purchase Agreement between Southern
California Energy Company and Vulcan/BN Geothermal Power Company,
dated April 1, 1986, incorporated by reference to Exhibit 10.14 to
EME's Form 10.
10.15 U.S. $325 million Bank of Montreal Revolver, dated October 29,
1993, incorporated by reference to Exhibit 10.15 to EME's Form 10.
10.15.1 U.S. $400 million Bank of America National Trust and Savings
Association Credit Agreement, dated October 27, 1994, incorporated
by reference to Exhibit 10.15.1 to EME's Form 10.
10.15.2 Conformed copy of the Amended and Restated U.S. $400 million Bank
of America National Trust and Savings Association Credit
Agreement, dated as of November 17, 1994, incorporated by
reference to Exhibit 10.15.2 to EME's Annual Report on Form 10-K
for the year ended December 31, 1994.
10.15.3 Conformed copy of the Second Amended and Restated U.S. $400
million Bank of America National Trust and Savings Association
Credit Agreement, dated as of October 11, 1996, incorporated by
reference to Exhibit 10.15.3 to EME's Annual Report on Form 10-K
for the year ended December 31, 1996.
10.16 Amended and Restated Ground Lease Agreement between Texaco
Refining and Marketing Inc. and March Point Cogeneration Company,
dated August 21, 1992, incorporated by reference to Exhibit 10.16
to EME's Form 10.
10.16.1 Amendment No. 1 to Amended and Restated Ground Lease Agreement
between Texaco Refining and Marketing Inc. and March Point
Cogeneration Company, dated August 21, 1992, incorporated by
reference to Exhibit 10.16 to EME's Form 10.
10.17 Memorandum of Agreement between Atlantic Richfield Company and
Products Cogeneration Company, dated September 17, 1987,
incorporated by reference to Exhibit 10.17 to EME's Form 10.
10.18 Memorandum of Ground Lease between Texaco Producing Inc. and
Sycamore Cogeneration Company, dated January 19, 1987,
incorporated by reference to Exhibit 10.18 to EME's Form 10.
10.19 Amended and Restated Memorandum of Ground Lease between Getty Oil
Company and Kern River Cogeneration Company, dated November 14,
1984, incorporated by reference to Exhibit 10.19 to EME's Form 10.
10.20 Memorandum of Lease between Sun Operating Limited Partnership and
Midway-Sunset Cogeneration Company, incorporated by reference to
Exhibit 10.20 to EME's Form 10.
10.21 Executive Supplemental Benefit Program, incorporated by reference
to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).
10.22 1981 Deferred Compensation Agreement, incorporated by reference to
Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).
10.23 1985 Deferred Compensation Agreement for Executives, incorporated
by reference to Exhibits to Forms 10-K filed by SCEcorp (File No.
1-2313).
10.24 1987 Deferred Compensation Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K
82
<PAGE>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
filed by SCEcorp (File No. 1-2313).
10.25 1988 Deferred Compensation Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
2313).
10.26 1989 Deferred Compensation Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
9936).
10.27 1990 Deferred Compensation Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
9936).
10.28 Annual Deferred Compensation Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
9936).
10.29 Executive Retirement Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
2313).
10.30 Long-Term Incentive Plan for Executive Officers, incorporated by
reference to the Registration Statement (File No. 33-19541) under
which SCEcorp registered securities to be offered pursuant to the
Plan under the Securities Act of 1933.
10.31 Estate and Financial Planning Program for Executive Officers,
incorporated by reference to Exhibits to Forms 10-K filed by
SCEcorp (File No. 1-9936).
10.32 Letter Agreement with Edward R. Muller, incorporated by reference
to Exhibit 10.32 to EME's Form 10.
10.33 Agreement with James S. Pignatelli, incorporated by reference to
Exhibit 10.33 to EME's Form 10.
10.34 Conformed copy of the Guarantee Agreement dated as of November 30,
1994, incorporated by reference to Exhibit 10.34 to EME's Form 10.
10.35 Indenture of Lease between Brooklyn Navy Yard Development
Corporation and Cogeneration Technologies, Inc., dated as of
December 18, 1989, incorporated by reference to Exhibit 10.35 to
EME's Annual Report on Form 10-K for the year ended December 31,
1994.
10.35.1 First Amendment to Indenture of Lease between Brooklyn Navy Yard
Development Corporation and Cogeneration Technologies, Inc., dated
November 1, 1991, incorporated by reference to Exhibit 10.35.1 to
EME's Annual Report on Form 10-K for the year ended December 31,
1994.
10.35.2 Second Amendment to Indenture of Lease between Brooklyn Navy Yard
Development Corporation and Cogeneration Technologies, Inc., dated
June 3, 1994, incorporated by reference to Exhibit 10.35.2 to
EME's Annual Report on Form 10-K for the year ended December 31,
1994.
10.35.3 Third Amendment to Indenture of Lease between Brooklyn Navy Yard
Development Corporation and Cogeneration Technologies, Inc., dated
December 12, 1994, incorporated by reference to Exhibit 10.35.3 to
EME's Annual Report on Form 10-K for the year ended December 31,
1994.
10.36 Conformed copy of A$200 million Bank of America National Trust and
Savings Association Credit Agreement dated November 22, 1994,
incorporated by reference to Exhibit 10.36 to EME's Annual Report
on Form 10-K for the year ended December 31, 1994.
10.36.1 Conformed copy of the Amended and Restated A$200 million Bank of
America National Trust and Savings Associated Credit Agreement
dated December 12, 1994, incorporated by reference to Exhibit
10.36.1 to EME's Annual Report on Form 10-K for the year ended
December 31, 1994.
10.36.2 Conformed copy of First Amendment to Amended and Restated A$200
million Bank of America National Trust and Savings Associated
Credit Agreement dated June 7, 1995, incorporated by reference to
Exhibit 10.36.2 to EME's Form 10-Q for the quarter ended September
30, 1995.
83
<PAGE>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
10.37 Amended and Restated Limited Partnership Agreement of Mission
Capital, L.P. dated as of November 30, 1994, incorporated by
reference to Exhibit 10.37 to EME's Annual Report on Form 10-K for
the year ended December 31, 1994.
10.38 Action of General Partner of Mission Capital, L.P. creating the 9-
7/8% Cumulative Monthly Income Preferred Securities, Series A,
dated as of November 30, 1994, incorporated by reference to
Exhibit 10.38 to EME's Annual Report on Form 10-K for the year
ended December 31, 1994.
10.39 Action of General Partner of Mission Capital, L.P. creating the 8-
1/2% Cumulative Monthly Income Preferred Securities, Series B,
dated as of August 8, 1995, incorporated by reference to Exhibit
10.39 to EME's Form 10-Q for the quarter ended June 30, 1995.
10.40 Power Purchase Contract between ISAB Energy, S.r.l. as Seller and
Enel, S.p.A. as Buyer, dated June 9, 1995, incorporated by
reference to Exhibit 10.40 to EME's Form 10-Q for the quarter
ended June 30, 1995.
10.41 400 million sterling pounds Barclays Bank Plc Credit Agreement,
dated December 18, 1995, incorporated by reference to Exhibit
10.41 to EME's Current Report on Form 8-K, No. 1-13434.
10.42 Guarantee by EME dated December 1, 1995 supporting Letter of
Credit issued by Bank of America National Trust and Savings
Association to secure payment of bonds issued pursuant to the
Brooklyn Navy Yard project tax-exempt bond financing, incorporated
by reference to Exhibit 10.42 to EME's Annual Report on Form 10-K
for the year ended December 31, 1995.
10.43 Guarantee by EME dated December 1, 1995 supporting Letter of
Credit issued by Bank of America National Trust and Savings
Association to secure Brooklyn Navy Yard's indemnity to the New
York City Industrial Development Agency pursuant to the Brooklyn
Navy Yard project tax-exempt bond financing, incorporated by
reference to Exhibit 10.43 to EME's Annual Report on Form 10-K for
the year ended December 31, 1995.
10.44 Guarantee by EME dated December 20, 1996 in favor of The Fuji
Bank, Limited, Los Angeles Agency, to secure Camino Energy
Company's payments pursuant to Camino Energy Company's Credit
Agreement and Defeasance Agreement, incorporated by reference to
Exhibit 10.44 to EME's Annual Report on Form 10-K for the year
ended December 31, 1996.
10.45 Power Purchase Agreement between National Power Corporation and
San Pascual Cogeneration Company International B.V., dated
September 10, 1997.*
10.46 Power Purchase Agreement between Gulf Power Generation Co., LTD.,
and Electricity Generating Authority of Thailand, dated December
22, 1997.*
21 List of Subsidiaries.*
27 Financial Data Schedule.*
*Filed herewith
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the fourth quarter of 1997.
(c) EXHIBITS
84
<PAGE>
The Exhibits filed with this report are listed in Item 14(a)(3) above.
(d) FINANCIAL STATEMENT SCHEDULES
The financial statement schedules filed with this report are listed in
Section 14(a)(2) above.
Financial information for the Cogeneration Group for the years ended
December 31, 1997, 1996 and 1995. The financial statements of the Cogeneration
Group present the combination of those entities that are 50% or less owned by
EME and that met the requirements of Rule 3-09 of Regulation S-X in 1995. There
were no entities which were 50% or less owned by EME that met the requirements
of Rule 3-09 of Regulation S-X in 1997 and 1996.
85
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Edison Mission Energy:
We have audited the accompanying combined statements of income, partners'
equity and cash flows of Kern River Cogeneration Company (a general
partnership between Getty Energy Company and Southern Sierra Energy Company),
Sycamore Cogeneration Company (a general partnership between Texaco
Cogeneration Company and Western Sierra Energy Company) and Watson
Cogeneration Company (a general partnership between Camino Energy Company and
Products Cogeneration Company), (collectively the Cogeneration Group) for the
year ended December 31, 1995. These financial statements are the
responsibility of the Group's management. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the results of the Cogeneration Group's
operations and cash flows for the year ended December 31, 1995, in conformity
with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Los Angeles, California
March 15, 1996
86
<PAGE>
THE COGENERATION GROUP
COMBINED STATEMENTS OF INCOME
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------
1997 1996 1995
---------- -------- ---------
(Unaudited) (Unaudited)
<S> <C> <C> <C>
OPERATING REVENUES
Sales of energy to SCE $402,839 $347,537 $318,964
Sales of energy to TEPI 11,715 9,406 8,405
Sales of energy to ARCO Products 26,423 23,631 19,249
Sales of steam to TEPI 89,682 72,038 64,150
Sales of steam to ARCO Products 48,216 43,121 35,018
-------- -------- --------
Total operating revenues 578,875 495,733 445,786
-------- -------- --------
OPERATING EXPENSES
Fuel 294,277 234,509 181,219
Plant operations 53,377 56,662 62,657
Depreciation and amortization 24,194 24,151 24,661
Administrative and general 8,014 5,733 6,824
-------- -------- --------
Total operating expenses 379,862 321,055 275,361
-------- -------- --------
Income from operations 199,013 174,678 170,425
-------- -------- --------
OTHER INCOME (EXPENSE)
Interest and other income 5,041 2,031 2,706
Interest expense (4,197) (5,673) (9,454)
-------- -------- --------
Total other income (expense) 844 (3,642) (6,748)
-------- -------- --------
NET INCOME $199,857 $171,036 $163,677
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
87
<PAGE>
THE COGENERATION GROUP
COMBINED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
(UNAUDITED)
DECEMBER 31,
------------------------
1997 1996
---------- ----------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 36,305 $ 48,334
Trade receivables - affiliates 62,800 57,051
Other receivables 603 825
Inventories 15,327 16,632
Prepaid expenses and other assets 2,963 3,009
-------- --------
Total current assets 117,998 125,851
-------- --------
PROPERTY, PLANT AND EQUIPMENT 672,082 652,534
Less accumulated depreciation and amortization 257,436 236,517
-------- --------
Net property, plant and equipment 414,646 416,017
-------- --------
OTHER ASSETS
Emission credits, net 17,488 19,584
Intangible assets, net 22,822 23,950
Other 168 890
-------- --------
Total other assets 40,478 44,424
-------- --------
TOTAL ASSETS $573,122 $586,292
======== ========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
88
<PAGE>
THE COGENERATION GROUP
COMBINED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
(UNAUDITED)
DECEMBER 31,
-------------------------
1997 1996
---------- ----------
<S> <C> <C>
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates $ 47,410 $ 46,680
Accounts payable and accrued liabilities 20,680 32,077
Current maturities of loans payable 13,404 13,404
-------- --------
Total current liabilities 81,494 92,161
-------- --------
LOANS PAYABLE, net of current maturities 55,966 69,370
-------- --------
MAINTENANCE ACCRUAL 10,505 9,160
-------- --------
Total liabilities 147,965 170,691
-------- --------
COMMITMENTS AND CONTINGENCIES (Note 7)
PARTNERS' EQUITY 425,157 415,601
-------- --------
TOTAL LIABILITIES AND PARTNERS' EQUITY $573,122 $586,292
======== ========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
89
<PAGE>
THE COGENERATION GROUP
COMBINED STATEMENTS OF PARTNERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
EME Texaco ARCO Total
Affiliates Affiliates Affiliates Equity
---------- ----------- ---------- ------
<S> <C> <C> <C> <C>
Balances at December 31, 1994 $196,456 $ 94,129 $106,503 $ 397,088
Cash distributions (79,550) (42,800) (38,250) (160,600)
Net income 81,182 49,010 33,485 163,677
-------- -------- -------- ---------
Balances at December 31, 1995 198,088 100,339 101,738 400,165
Cash distributions (Unaudited) (77,060) (40,800) (37,740) (155,600)
Net income (Unaudited) 84,865 52,845 33,326 171,036
-------- -------- -------- ---------
Balances at December 31, 1996 (Unaudited) 205,893 112,384 97,324 415,601
Cash distributions (Unaudited) (94,326) (53,900) (42,075) (190,301)
Net Income (Unaudited) 99,139 60,466 40,252 199,857
-------- -------- -------- ---------
Balances at December 31, 1997 (Unaudited) $210,706 $118,950 $ 95,501 $ 425,157
======== ======== ======== =========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
90
<PAGE>
THE COGENERATION GROUP
COMBINED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------
1997 1996 1995
---------- ---------- ----------
(Unaudited) (Unaudited)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 199,857 $ 171,036 $ 163,677
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 24,194 24,151 24,661
(Increase) decrease in receivables (5,527) (7,180) 5,595
Decrease (increase) in inventories 1,305 1,177 (1,519)
(Decrease) increase in payables (5,572) 27,800 (1,053)
(Decrease) increase in maintenance accrual (3,750) 3,673 5,456
Other, net 47 (1,630) (411)
--------- --------- ---------
Net cash provided by operating activities 210,554 219,027 196,406
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (19,548) (11,512) (7,386)
--------- --------- ---------
Net cash used in investing activities (19,548) (11,512) (7,386)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from escrow account 670 1,534 1,488
Loan repayments (13,404) (24,951) (25,100)
Distribution to partners (190,301) (155,600) (160,600)
--------- --------- ---------
Net cash used in financing activities (203,035) (179,017) (184,212)
--------- --------- ---------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (12,029) 28,498 4,808
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 48,334 19,836 15,028
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 36,305 $ 48,334 $ 19,836
========= ========= =========
SUPPLEMENTAL CASH FLOW INFORMATION
Interest paid $ 4,257 $ 5,997 $ 9,553
========= ========= =========
SUPPLEMENTAL DISCLOSURE OF NONCASH
FINANCING ACTIVITIES
Additions to property, plant and equipment
received in settlement of certain receivables $ -- $ -- $ 778
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
91
<PAGE>
THE COGENERATION GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 1997 (UNAUDITED), 1996 (UNAUDITED) AND 1995
NOTE 1. GENERAL
- ----------------
Principles of Combination
Edison Mission Energy (EME), a wholly owned subsidiary of The Mission Group, a
wholly owned non-utility subsidiary of Edison International, the parent holding
company of Southern California Edison Company (SCE), has a general partnership
interest in Kern River Cogeneration Company (Kern River), Sycamore Cogeneration
Company (Sycamore) and Watson Cogeneration Company (Watson) (jointly referred to
herein as the Group). SSEC, WSEC and CEC (as defined below) are separate legal
entities from EME. The accompanying combined financial statements have been
prepared for purposes of EME complying with certain requirements of the
Securities and Exchange Commission.
Kern River is a general partnership between Getty Energy Company (GEC), a
wholly owned subsidiary of Texaco Inc. (Texaco), and Southern Sierra Energy
Company (SSEC), a wholly owned subsidiary of EME. Kern River owns and operates
a 300-MW natural gas-fired cogeneration facility located near Bakersfield,
California, which sells electricity to SCE and which sells electricity and steam
to Texaco Exploration and Production Inc. (TEPI), a wholly owned subsidiary of
Texaco, for use in TEPI's enhanced oil recovery operations in the Kern River Oil
Field. Partnership income (loss) is allocated equally to the partners.
Sycamore is a general partnership between Texaco Cogeneration Company (TCC), a
wholly owned subsidiary of Texaco, and Western Sierra Energy Company (WSEC), a
wholly owned subsidiary of EME. Sycamore owns and operates a 300-MW natural
gas-fired cogeneration facility located near Bakersfield, California, which
sells electricity to SCE and which sells steam to TEPI for use in TEPI's
enhanced oil recovery operations in the Kern River Oil Field. Partnership
income (loss) is allocated equally to the partners.
Watson is a general partnership between Carson Cogeneration Company (CCC), a
wholly owned subsidiary of CH-Twenty, Inc., a majority owned subsidiary of
Atlantic Richfield Company (ARCO), Products Cogeneration Company (PCC), a wholly
owned subsidiary of ARCO and Camino Energy Company (CEC), a wholly owned
subsidiary of EME. CCC, PCC and CEC own 49 percent, 2 percent and 49 percent,
respectively. Watson owns and operates a 385-MW natural gas-fired cogeneration
facility located in Carson, California, which sells electricity to SCE and which
sells electricity and steam to ARCO Products Company (ARCO Products) for use at
ARCO Products' refinery. Partnership income (loss) is allocated based upon the
partners' respective ownership percentage.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
Basis of Presentation
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
92
<PAGE>
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Inventories
Inventories are comprised of materials and supplies, and are stated at their
lower of average cost or market.
Property, Plant and Equipment
All costs, including interest and field overhead expenses, incurred during
construction and the precommission phase of the facilities were capitalized as
part of the cost of the facilities. Revenue earned during the precommission
phase was offset against the costs of the facilities. The facilities and
related equipment are being depreciated on a straight-line basis over
approximately 30 years, which is the estimated useful lives of the facilities.
Emission Credits
Two of the Group's facilities were required to obtain assignments of emission
offset credits in order to be certified by the California Energy Commission.
These credits were required to meet the current environmental regulations as
they relate to the emissions being produced from the operation of these
facilities. The cost of these emission credits are stated net of accumulated
amortization of $23.2 million and $21.1 million at December 31, 1997 and 1996,
respectively (see Note 5). The emission credits are being amortized on a
straight-line basis over 21 years.
Intangible Assets
Intangible assets are stated net of accumulated amortization of $13 million
and $11.9 million at December 31, 1997 and 1996, respectively, and consist of
outside boundary limit facilities, refinery infrastructure, environment permits
and land use, as outlined in the various partnership agreements, contributed to
the Group. All of the intangible assets relate to the operations of the various
facilities, and as a result, are being amortized on a straight-line basis over
the estimated useful life of the facilities.
Statements of Cash Flows
For purposes of reporting cash flows, the Group considers short-term temporary
cash investments with an original maturity of three months or less to be cash
equivalents.
Maintenance Accruals
The Group performs scheduled inspections and major overhauls periodically over
the life of their combustion turbines. Generally, expenses for these events are
accrued for on a straight-line basis over the expected operating-hour interval
between each like maintenance event. Expenditures for minor maintenance,
repairs and renewals are charged to expense as incurred. Expenditures for
additions and improvements are capitalized.
The accruals for repair and maintenance events are based on management's
estimates of what these events will cost at the time the events occur. Due to
fluctuations in prices and changes in the timing of the scheduled events, the
estimated costs of these events can differ from actual costs incurred.
93
<PAGE>
Fair Value of Financial Instruments
The carrying amount of the short-term investments approximates fair value due
to the short maturities of such investments. The estimated fair value of loans
payable is discussed in Note 4.
Reclassifications
Certain prior year amounts have been reclassified to conform with current year
presentation.
NOTE 3. PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------
Plant and equipment consist of the following:
<TABLE>
<CAPTION>
(Unaudited)
December 31,
-----------------
1997 1996
------ ------
<S> <C> <C>
(in millions)
Plant and equipment
Power plant facilities $649.0 $644.8
Building, furniture and office equipment 23.0 7.7
------ ------
672.0 652.5
Less -- Accumulated depreciation and amortization 257.4 236.5
------ ------
$414.6 $416.0
====== ======
</TABLE>
NOTE 4. LOANS PAYABLE
- ----------------------
<TABLE>
<CAPTION>
(Unaudited)
December 31,
-----------------
1997 1996
------ ------
<S> <C> <C>
(in millions)
Watson project:
Note payable to ARCO (5% at 12/31/97)
(5% at 12/31/96) $ 27.4 $ 27.4
Note payable to CEC (5% at 12/31/97)
(5% at 12/31/96) 26.3 26.3
Sycamore project:
$165 million Loan and Credit
Agreement due 1999
(Eurodollar rate + 0.625%) (6.4% at 12/31/97)
(6.2% at 12/31/96) 15.7 29.1
------ ------
Subtotal 69.4 82.8
Current maturities of loans payable (13.4) (13.4)
------ ------
Total $ 56.0 $ 69.4
====== ======
</TABLE>
The above agreement for the Sycamore project is secured by certain assets of
Sycamore, and places certain restrictions on capital distributions. In
addition, this agreement requires Sycamore to maintain escrow deposits based
upon outstanding loan amounts. Based upon borrowing rates currently available
to Sycamore for long-term debt with similar terms and maturity, the fair value
of the amount outstanding under this agreement approximates the carrying value.
94
<PAGE>
The fair value of the two Watson project notes was approximately $53 million
at December 31, 1997 and 1996. In February 1996, the interest rates on the two
Waston project notes were reduced to 5% and the maturity dates extended to April
2008.
Annual maturities on the loans payable at December 31, 1997 are as follows
(dollars in millions):
YEAR
----
1998 $13.4
1999 2.2
2000 --
2001 --
2002 --
Thereafter 53.8
-----
Total $69.4
=====
NOTE 5. RELATED-PARTY TRANSACTIONS/CONTRACTUAL OBLIGATIONS
- -----------------------------------------------------------
Operating and Other Costs
The amounts incurred by EME, Texaco and their respective affiliates for
operating and other costs charged to the Group, which are not disclosed
elsewhere, were as follows:
<TABLE>
<CAPTION>
(in millions)
1997 1996 1995
---- ---- ----
(unaudited) (unaudited)
<S> <C> <C> <C>
Texaco and affiliates $ 4.4 $ 4.6 $ 4.5
EME and affiliates 1.2 2.4 2.8
</TABLE>
Emission Credits
Certain affiliates of Texaco assigned their rights to certain emission offset
credits to certain of the Group for a period of 21 years. These emission offset
credits were earned by the Texaco affiliates by reducing specified emissions at
other of their operations. Such credits are used by the Group to allow certain
of the Group's facilities to operate under current environmental regulations.
The credits were required by those facilities in order to be certified by the
California Energy Commission and are required to be maintained throughout the
period of operations of those facilities. The credits were reflected as a
capital contribution by such entities at the fair market value of $40.8 million.
Fuels Management Agreement
Certain of the Group are party to agreements with Texaco Natural Gas, Inc.
(TNGI), whereby TNGI is to procure and manage all fuel-gas supplies and
transportation for two of the facilities (except fuel-gas supplies procured and
delivered under tariff-gas contracts, provided under an excepted contract or
otherwise excluded from these agreements by the mutual consent of the partners).
The original termination date of the agreements with TNGI was December 31,
1995. TNGI received a fixed service fee of $.0075 per MMBtu of fuel gas
supplied to certain of the Group, and a variable
95
<PAGE>
incentive fee based on the utility fuel cost applicable to such Group. The
agreements include a minimum annual fee of $.015 per MMBtu of fuel gas utilized
if the total of the fixed service fee and variable incentive fee is less than
the minimum annual fee. The amounts incurred under these agreements were $118.5
million, which included fees earned by TNGI of $3.7 million, for the year ended
December 31, 1995.
As of January 1, 1996, the Amended and Restated Fuel Management Agreement,
terminating on October 1, 2002, was entered into such that TNGI will receive a
fixed service fee of $.0375 per MMBtu of fuel gas supplied to certain of the
Group. The amounts incurred under the amended agreements were $183.5 million
and $147.7 million which included fees earned by TNGI of $0.4 million and $2.6
million, for the two years ended December 31, 1997.
One of the Group has entered into a fuel (refinery gas and butane) purchase
agreement with a subsidiary of ARCO. Such Group's purchases under this
agreement amounted to $40.9 million, $38.4 million and $24.2 million for the
three years ended December 31, 1997, 1996 and 1995, respectively.
Operation and Maintenance Agreement
Two of the Group have agreements with Edison Mission Operation & Maintenance,
Inc. (EMOM), a wholly owned subsidiary of EME, whereby EMOM shall perform all
operation and maintenance activities necessary for the production of electricity
and steam by such Group facilities. The agreements will continue until
terminated by either party. EMOM is paid for all costs incurred in connection
with operating and maintaining the facility. EMOM may also earn incentive
compensation as set forth in the agreements. The amounts incurred by the Group
under these agreements were $6.3 million, $6 million and $6.2 million which
included incentive compensation earned by EMOM of $0.9 million for each of the
three years ended December 31, 1997, 1996 and 1995, respectively.
One of the Group has an agreement with a subsidiary of ARCO, whereby such
subsidiary shall perform all operation and maintenance activities necessary for
the production of electricity and steam by such Group's facility. The agreement
will continue until termination of the Power Purchase Agreement in April 2008.
The ARCO subsidiary is reimbursed for all costs incurred in connection with
operating and maintaining the facility. The amounts incurred under this
agreement were $5 million, $4.9 million and $5.4 million for the three years
ended December 31, 1997, 1996 and 1995, respectively. Additionally, ARCO
provides other ancillary services under a service contract for a fee. Total
service fees earned by ARCO were $1.4 million, $1.3 million and $1.3 million for
the three years ended December 31, 1997, 1996 and 1995, respectively.
Steam Purchase and Sale Agreements
Certain of the Group have agreements with TEPI for the sale of steam generated
by such Group's facilities. The agreements terminate 20 years from the date of
the first sale of steam thereunder. TEPI pays such Group a steam fuel charge
based upon the quantity and quality of steam delivered during the month, which
is priced at the lesser of the current Southern California Gas Company Border
Gas Price, or the weighted average posted price of Kern River Crude, less any
severance, excise or windfall profit taxes, and a processing charge per MMBtu as
defined in the agreements. The quantity of steam sold under this contract is
expected to be sufficient for such Group to maintain qualifying facility status.
Total sales of steam under these agreements amounted to approximately $89.7
million, $72 million and $64.2 million for the three years ended December 31,
1997, 1996 and 1995, respectively.
96
<PAGE>
These agreements have been amended whereby such Group will reduce a portion of
steam prices beginning in 1999 and to a limited extent in 1997. The amount of
future reductions in annual revenues could total approximately $25 million.
Additionally, one of the Group has contracted to sell steam and power
generated by its facility to the ARCO subsidiary's Los Angeles refinery under
separate agreements. Total sales under these contracts amounted to approximately
$74.6 million, $66.8 million and $54.3 million for the three years ended
December 31, 1997, 1996 and 1995, respectively.
Power Purchase Agreements
One of the Group has an agreement with TEPI for the sale of contract capacity
and net energy. This agreement will remain in effect until August 8, 2005. The
amounts paid for the contract capacity and net energy are based on the same
terms as provided for in the agreements with SCE (discussed below). Total sales
of power under the agreement with TEPI amounted to approximately $11.7 million,
$9.4 million and $8.4 million for the three years ended December 31, 1997, 1996
and 1995, respectively.
The Group has agreements with SCE for the sale of contract capacity and net
energy generated by the facilities. These agreements will remain in effect 20
years from the Firm Operation Date of the relevant facility. SCE pays the Group
for energy based upon the price of SCE's Avoided Fuel Cost, the quantity of
kilowatts delivered, the contracted heat rate allocated to on-peak, mid-peak and
off-peak hours and a factor as defined in the agreements to account for system
line loss at the point of delivery. SCE also pays the Group for firm capacity
based upon a contracted amount per kilowatt year. Total sales of energy under
these agreements amounted to $402.8 million, $347.5 million and $319 million for
the three years ended December 31, 1997, 1996 and 1995, respectively.
As discussed above, the electric power generated by the Group is primarily
sold to SCE pursuant to long-term power sales contracts. When negotiating power
sales contracts, EME negotiates contracts which are expected to result in
consistent cash flow under a wide range of economic and operating circumstances.
To accomplish this end, EME structures its long-term contracts so that
fluctuations in fuel costs will produce similar fluctuations in electric
revenues and by entering into long-term fuel supply and transportation
agreements. In addition, the operation of the facilities involves many risks
including the breakdown or failure of equipment or processes, performance below
expected levels of output, interruptions in fuel supply, pipeline disruptions,
disruptions in the supply of electrical energy, violation of permit
requirements, operator error, the inability to meet expected efficiency
standards and catastrophic events. The occurrence of any of these events could
result in extended unavailability under the power sales contracts which may
entitle the purchaser thereunder to terminate the relevant power sales
contracts.
Natural Gas Supply and Transportation Agreements
The Group purchases gas on the spot market. As such, the Group may be
exposed, in the short-term, to fluctuations in the price of natural gas.
Fluctuations in the prices paid for gas are implicitly tied to the revenues
received for either power or steam under the agreements.
97
<PAGE>
NOTE 6. INCOME TAXES
- ---------------------
Income taxes are not recorded by the Group because the net income or loss
allocated to the partners is included in their respective income tax returns.
NOTE 7. COMMITMENTS AND CONTINGENCIES
- --------------------------------------
Future Obligations
Pursuant to amendments made in 1990 to the Federal Clean Air Act and the
California Clean Air Act, the Group is required to reduce its nitrogen oxide
(NOx) emissions. To fulfill these requirements one of the Group retrofitted its
combustion turbines to employ a Dry-Lo NOx (DLN) technology. One of the Group
is scheduled to complete the retrofit of its combustion turbines to coincide
with maintenance overhauls scheduled through 1999. Such Group's management
estimates the future obligations of these DLN conversions will be $22.4 million.
The Group will capitalize $11.6 million of these costs related to the DLN
conversions. It is further anticipated that operating cash flows will be used
to fund the DLN conversions.
Ship-or-Pay
Pursuant to the Master Agreement, entered into as of December 1, 1994, certain
of the Group executed a Security of Supply Agreement with an affiliated
partnership of EME and Texaco. Such Group has agreed to accept and underwrite,
on a pro-rata basis, a portion of Texaco's commitment pursuant to the
transportation agreement (the Transportation Agreement) between Texaco, the
Mojave Pipeline Company (Mojave) and the El Paso Pipeline Company (El Paso),
dated February 15, 1989 and extending through March 31, 2008. The Company has
agreed that Mojave and El Paso shall be the exclusive means of delivery for
certain of the Group of the lesser of 75% of the annual total natural gas fuel
requirements for such Group and 52,012,500 MMBtu per year.
Except upon the occurrence of certain permissible events, two of the Group are
subject to certain terms and conditions, whereby failure to transport the
required quantity of natural gas on the Mojave Pipeline will result in the Group
paying $0.63 per deficit MMBtu. Such Group will share any ship-or-pay
liabilities on a pro-rata basis (as defined in the Transportation Agreement)
with the affiliated partnership.
For each of the years in the three-year period ended December 31, 1997, the
transportation quantities required under the Transportation Agreement were met.
It is the opinion of the relevant Group's management that these commitments will
continue to be met based upon current projections for the operations of such
Group's facilities.
98
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
EDISON MISSION ENERGY
(Registrant)
By: /s/ James V. Iaco, Jr.
---------------------------------------------------------------------
JAMES V. IACO, JR., SENIOR VICE PRESIDENT and CHIEF FINANCIAL OFFICER
Date: March 30, 1998
--------------------------------------------------------------------------
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.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
Principle Executive Officer:
/s/ Edward R. Muller President and Chief Executive Officer March 30, 1998
Controller or Principal Accounting Officer:
/s/ Thomas E. Legro Vice President and Controller March 30, 1998
Majority of Board of Directors:
/s/ Alan J. Fohrer Chairman of the Board March 30, 1998
/s/ Robert M. Edgell Director March 30, 1998
/s/ Bryant C. Danner Director March 30, 1998
</TABLE>
99
<PAGE>
EXHIBIT 10.45
================================================================================
POWER PURCHASE AGREEMENT
between
National Power Corporation
and
San Pascual Cogeneration Company
International B.V.
SAN PASCUAL
COGENERATION POWER
PRODUCTION FACILITY PROJECT
September 10, 1997
================================================================================
<PAGE>
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
Page No.
<S> <C>
RECITALS........................................................... 1
ARTICLE 1 - DEFINITIONS AND INTERPRETATION......................... 2
1.1 DEFINITIONS............................................ 2
-----------
1.2 HEADINGS............................................... 9
--------
1.3 INTERPRETATION......................................... 9
--------------
1.4 ABBREVIATIONS.......................................... 10
-------------
ARTICLE 2. - SCOPE OF AGREEMENT.................................... 11
2.1 THE COGENERATION POWER PRODUCTION FACILITY............. 11
------------------------------------------
2.2 CONSTRUCTION........................................... 11
------------
2.3 COST OF CONSTRUCTION................................... 11
--------------------
2.4 THE SITE............................................... 11
--------
2.5 CONSENTS............................................... 11
--------
2.6 SUPPLY OF ELECTRICITY.................................. 11
---------------------
2.7 TRANSMISSION LINE...................................... 12
-----------------
2.8 OPERATION.............................................. 13
---------
2.9 POWER AND ENERGY....................................... 13
----------------
2.10 STEAM.................................................. 13
-----
2.11 COSTS OF NPC........................................... 13
------------
2.12 OWNERSHIP OF COGENERATION POWER PRODUCTION FACILITY.... 13
---------------------------------------------------
2.13 CERTAIN RESPONSIBILITIES OF SPCC....................... 14
--------------------------------
2.14 CERTAIN RESPONSIBILITIES OF NPC........................ 14
-------------------------------
2.15 MUTUAL COOPERATION..................................... 14
------------------
2.16 FUEL SUPPLY............................................ 15
-----------
ARTICLE 3 - CONSTRUCTION........................................... 15
3.1 PROJECT MILESTONE DATES................................ 15
-----------------------
3.2 DELAY IN ACHIEVING MILESTONE........................... 17
----------------------------
3.3 SPCC'S RIGHTS.......................................... 17
-------------
3.4 LOCAL CONTRACTS........................................ 17
---------------
3.5 MONITOR PROGRESS....................................... 18
----------------
3.6 DISCLAIMER............................................. 19
----------
3.7 CONSULTATION........................................... 19
------------
3.8 DRAWINGS AND TECHNICAL DETAILS......................... 19
------------------------------
3.9 CONFIDENTIALITY........................................ 20
---------------
3.10 BOND................................................... 21
----
ARTICLE 4 - TESTING................................................ 23
4.1 TESTING PROCEDURES..................................... 23
------------------
4.2 WITNESSING OF TESTS.................................... 24
-------------------
4.3 GUARANTEE TEST......................................... 24
--------------
4.4 PERFORMANCE TEST....................................... 25
----------------
4.5 COST OF TESTING AND PURCHASE OF ELECTRICITY............ 26
-------------------------------------------
4.6 CERTIFICATION.......................................... 26
-------------
4.7 DEEMED COMPLETION...................................... 26
-----------------
ARTICLE 5 - OPERATION OF THE COGENERATION POWER PRODUCTION FACILITY 27
5.1 SPCC'S RESPONSIBILITIES................................ 27
-----------------------
5.2 DOWNTIME............................................... 28
--------
5.3 AVAILABILITY........................................... 28
------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Page No.
<S> <C>
5.4 OPERATION.............................................. 28
---------
5.5 SPCC'S RIGHTS.......................................... 29
-------------
5.6 NPC'S OBLIGATIONS...................................... 29
-----------------
5.7 ENVIRONMENTAL IMPACT................................... 29
--------------------
5.8 SAFETY AND TECHNICAL GUIDELINES/ GRID CODE............. 29
------------------------------------------
ARTICLE 6 - SALE OF ELECTRICITY.................................... 30
6.1 SUPPLY TO NPC.......................................... 30
-------------
6.2 QUANTITY............................................... 30
--------
6.3 DELIVERY............................................... 30
--------
6.4 FEES................................................... 30
----
6.5 INVOICES............................................... 31
--------
6.6 PAYMENT BY NPC......................................... 31
--------------
6.7 NO SET-OFF............................................. 31
----------
6.8 DISPUTES............................................... 31
--------
6.9 DOLLAR PAYMENTS........................................ 31
---------------
6.10 COST OF PAYMENTS....................................... 31
----------------
6.11 PESO PAYMENTS.......................................... 32
-------------
6.12 PAYMENTS TO NPC........................................ 32
---------------
6.13 DOLLAR DEFICIENCY...................................... 32
-----------------
6.14 CHANGE IN CIRCUMSTANCES................................ 32
-----------------------
6.15 CONVERSION TO OTHER FUEL............................... 33
------------------------
ARTICLE 7 - TERM AND TERMINATION................................... 34
7.1 TERM................................................... 34
----
7.2 TERMINATION BY NPC..................................... 34
------------------
7.3 TERMINATION BY SPCC.................................... 34
-------------------
7.4 EXERCISE OF TERMINATION PAYMENT BY NPC................. 34
--------------------------------------
7.5 PRE-COMPLETION TERMINATION AND PAYMENT................. 35
--------------------------------------
7.6 POST-FACILITY COMPLETION TERMINATION AND PAYMENT....... 35
------------------------------------------------
7.7 DEDUCTIONS............................................. 36
----------
ARTICLE 8 - REPRESENTATIONS, WARRANTIES AND COVENANTS OF SPCC...... 36
8.1 CORPORATE EXISTENCE.................................... 36
-------------------
8.2 GOVERNMENT AUTHORIZATIONS.............................. 36
-------------------------
8.3 COMPLIANCE WITH STANDARDS.............................. 36
-------------------------
8.4 COMPLIANCE WITH LAWS................................... 36
--------------------
8.5 SPCC'S WARRANTY AGAINST CORRUPTION..................... 36
----------------------------------
ARTICLE 9 - REPRESENTATIONS, WARRANTIES AND COVENANTS OF NPC....... 37
9.1 CORPORATE EXISTENCE.................................... 37
-------------------
9.2 GOVERNMENT AUTHORIZATIONS.............................. 37
-------------------------
ARTICLE 10- TAXES.................................................. 37
10.1 RESPONSIBILITY FOR TAXES............................... 37
------------------------
10.2 PAYMENT RESPONSIBILITIES............................... 38
------------------------
10.3 PAYMENTS FREE AND CLEAR................................ 38
-----------------------
10.4 LATE PAYMENT........................................... 39
------------
ARTICLE 11- INSURANCE.............................................. 39
11.1 INSURANCE.............................................. 39
---------
11.2 ENDORSEMENTS........................................... 39
------------
ARTICLE 12- TRANSMISSION LINE...................................... 39
12.1 OWNERSHIP AND RESPONSIBILITIES......................... 39
------------------------------
12.2 FAILURE TO TIMELY COMPLETE............................. 40
--------------------------
12.3 TRANSFER OF OBLIGATION TO SPCC......................... 40
------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Page No.
<S> <C>
ARTICLE 13 - FORCE MAJEURE......................................... 40
13.1 FORCE MAJEURE.......................................... 40
-------------
13.2 EXCEPTIONS............................................. 42
----------
13.3 PROCEDURE.............................................. 42
---------
13.4 CONSULTATION........................................... 43
------------
13.5 EXTENSION OF TIME...................................... 43
-----------------
ARTICLE 14 - EXPERT................................................ 43
14.1 APPLICATION OF ARTICLE................................. 43
----------------------
14.2 APPOINTMENT............................................ 43
-----------
14.3 ELIGIBILITY............................................ 44
-----------
14.4 PROCEDURES............................................. 44
----------
ARTICLE 15 - SEVERAL OBLIGATIONS................................... 46
ARTICLE 16 - NOTICES............................................... 46
16.1 WRITING................................................ 46
-------
16.2 ADDRESSES.............................................. 46
---------
ARTICLE 17 - WAIVER................................................ 47
ARTICLE 18 - BENEFIT OF AGREEMENT.................................. 47
18.1 ASSIGNMENT BY NPC...................................... 47
-----------------
18.2 NPC PRIVATIZATION...................................... 47
-----------------
18.3 ASSIGNMENT BY SPCC..................................... 47
------------------
18.4 SPCC PHILIPPINES....................................... 48
----------------
18.5 EFFECT OF ASSIGNMENT................................... 48
--------------------
ARTICLE 19 - DISPUTE RESOLUTION.................................... 48
19.1 REGULAR MEETINGS....................................... 48
----------------
19.2 AMICABLE SETTLEMENT.................................... 48
-------------------
ARTICLE 20 - ENTIRE AGREEMENT...................................... 49
ARTICLE 21 - GOVERNING LAW......................................... 49
ARTICLE 22 - DISCLAIMER............................................ 49
ARTICLE 23 - ARBITRATION........................................... 49
ARTICLE 24 - IMMUNITY.............................................. 50
ARTICLE 25 - EFFECT OF ARTICLE HEADINGS............................ 50
ARTICLE 26 - SEVERABILITY.......................................... 50
ARTICLE 27 - LIABILITY............................................. 50
27.1 LIMIT OF LIABILITY..................................... 50
------------------
27.2 NPC INDEMNITY.......................................... 51
-------------
27.3 CROSS INDEMNITY........................................ 51
---------------
ARTICLE 28 - EFFECTIVE DATE AND CONDITIONS PRECEDENT 51
28.1 EFFECTIVE DATE......................................... 51
--------------
28.2 CONDITIONS PRECEDENT................................... 53
--------------------
28.3 TERMINATION FOR FAILURE TO OBTAIN CERTAIN GOVERNMENT
----------------------------------------------------
APPROVALS.............................................. 54
---------
ARTICLE 29 - COUNTERPART EXECUTION................................. 55
</TABLE>
<PAGE>
POWER PURCHASE AGREEMENT
------------------------
KNOW ALL MEN BY THESE PRESENTS
This Power Purchase Agreement ("Agreement") is made and entered into the 10th
day of September, 1997 by and between:
SAN PASCUAL COGENERATION COMPANY INTERNATIONAL B.V. ("SPCC"), a private
corporation duly organized and existing under the laws of the Netherlands with
its principal address at 8/F 8750 Ayala Avenue, 1226 Makati City, Philippines,
represented by its Managing Directors Martin D. Considine and Robert E. Driscoll
who are duly authorized to represent it in this Agreement
- and -
The NATIONAL POWER CORPORATION ("NPC"), a government owned and controlled
corporation duly organized and existing under and by virtue of Republic Act No.
6395, as amended, with its principal office at the corner of Agham Road and
Quezon Avenue, Diliman, Quezon City, Philippines, represented herein by its
President, Guido Alfredo A. Delgado, who is duly authorized to represent it in
this Agreement.
RECITALS
WHEREAS, NPC has called for the development of new power facilities to support
and maintain the Philippines' economic growth;
WHEREAS, On July 27, 1993, the Department of Energy of the Republic of the
Philippines issued a Certificate of Conditional Accreditation to SPCC's
Cogeneration Project as a Private Sector Generation Facility ("PSGF") pursuant
to Article 12, paragraphs c.1 and c.3 of Republic Act No. 7638 and Executive
Order No. 215, which Certificate of Accreditation was renewed on December 28,
1994 and March 6, 1995, and was subsequently extended on the following dates:
March 7, 1996, March 7, 1997, and most recently on March 19, 1997, which last
extension is valid up to December 1, 1997 and will be replaced by a final
Certificate of Accreditation to be obtained by SPCC after this Agreement has
been signed;
WHEREAS, pursuant to the conditions of the Certificate of Conditional
Accreditation, SPCC submitted a Project proposal for a Cogeneration Plant to
NPC;
WHEREAS, NPC, after having evaluated the Project proposal and accepting the
same, submitted the proposal to the National Economic and Development Authority
(NEDA) for approval;
WHEREAS, on August 5, 1997, the NEDA Board approved the Project;
WHEREAS, NPC has issued to the public a notice inviting interested parties to
offer a competing proposal (Price Test) for the Project;
<PAGE>
WHEREAS, NPC, having received no competing proposals during the price test and
after NPC Board and NEDA/ICC Board approval, issued a letter of award to SPCC on
August 21, 1997;
WHEREAS, pursuant to NPC's acceptance of the Project proposal and NEDA's
approval of the Project, SPCC has agreed to build, operate and own the
Cogeneration Power Production Facility and NPC has agreed to accept electricity
generated by the Cogeneration Power Production Facility upon the terms and
subject to the conditions hereinafter set forth;
WHEREAS, the proponents of the Project are Texaco Inc. and Edison Mission
Energy;
WHEREAS, SPCC has caused or will cause the formation of a Philippine entity
known or to be known as the San Pascual Cogeneration Company Philippines Limited
duly organized and existing under the laws of the Republic of the Philippines
with its principal address at 6750 Ayala Avenue 8F, Makati, Metro Manila for the
purpose of undertaking certain work in respect of the building and operating the
Cogeneration Power Production Facility as defined herein.
NOW IT IS HEREBY AGREED as follows:
ARTICLE 1 - DEFINITIONS AND INTERPRETATION
1.1 DEFINITIONS. In this Agreement and the Recitals hereto and when used with
------------
capital initial letters:
"Abandon", "Abandoned", and "Abandonment" shall have the meaning ascribed
thereto in Article 3.10(d);
"Accession Undertaking" means an agreement substantially in the form set
out in the Twelfth Schedule (Form of Accession Undertaking) pursuant to
which SPCC Philippines agrees to become a party hereto as therein provided;
"Affiliate" means, in respect of a Party, any person which controls
(directly or indirectly) that Party and any other person controlled
(directly or indirectly) by such first mentioned person, including, where
the Party is a company, the ultimate holding company of such Party and any
subsidiary (direct or indirect) of such holding company;
"Agreed Interest Rate" means, in respect of Dollars, the overnight United
States Federal Funds rate plus two percentage points per annum and, in
respect of Pesos, the T-Bill Rate plus two percentage points per annum, in
each case compounded every thirty days; for the purposes of the foregoing,
"T-Bill Rate" means, in respect of any day for which interest based on such
rate is being calculated under this Agreement, the rate per annum at which
Philippine Treasury Bills (with terms of thirty days or, if no such bill is
issued, such bill which is issued having the term nearest to thirty days)
issued by the Government of the Republic of the Philippines on the Monday
immediately preceding such day or, if there were no Treasury Bills issued
on such Monday, on the day immediately preceding such Monday on which
Treasury Bills were issued;
<PAGE>
"Agreement" means this Power Purchase Agreement (PPA), and all schedules,
attachments and exhibits, as amended from time to time by instrument in
writing duly signed by or on behalf of the Parties;
"Ambient Conditions" shall mean 32 degrees Centigrade ambient air
temperature at ambient air pressure (1013 mbar), 85% relative humidity and
28 degrees Centigrade cooling water inlet temperature and 0.85 lagging
power factor;
"Ancillary Services" has the meaning ascribed to it in the Second Schedule;
"Appointor" has the meaning ascribed to it in Article 14.2.3;
"Availability" means, at any time and from time to time during the
Cooperation Period, the capability of the Cogeneration Plant to generate
electricity in accordance with this Agreement;
"Available" means capable of generating electricity in accordance with this
Agreement;
"Availability Fees" means Capital Recovery Fees and Fixed Operating and
Maintenance Fees;
"Bangko Sentral ng Pilipinas" means the Bangko Sentral ng Pilipinas or any
governmental authority which succeeds to the functions thereof;
"Base Energy Rate" has the meaning ascribed to it in the Eighth Schedule;
"Billing Period" means a period commencing immediately after the taking of
a photograph of the electricity meters on the twenty-fifth day of a
Calendar Month pursuant to the Seventh Schedule and ending upon the taking
of such a photograph on the twenty-fifth day of the next Calendar Month;
however, the first Billing Period shall commence on the taking of such a
photograph as soon as practicable after the Commercial Operation Date and
end on the next twenty-fifth day of a Calendar Month, and the last Billing
Period shall end upon the taking of such a photograph on the last day of
the Cooperation Period;
"Black Start" means the capability of the Cogeneration Power Production
Facility to start up and supply electricity to the NPC grid in accordance
with this Agreement without the need to import from NPC electricity to the
Cogeneration Power Production Facility;
"BOI" means the Board of Investments of the Republic of the Philippines or
any governmental authority which succeeds to the functions thereof;
"Bond" means a confirmed standby letter of credit as mentioned in Article
3.10;
"Business Day" shall mean any Day (other than Saturday or Sunday) on which
banks are authorized to be open for business in Manila;
"Calendar Month" means a month commencing on the first day of a month;
"Calendar Year" means a year commencing on January 1;
<PAGE>
"Caltex" means Caltex (Philippines) Inc., and its successors or assignees;
"Capital Recovery Fees" or "CRF" has the meaning ascribed to it in the
Eighth Schedule (Delivery of Power and Energy);
"Cocochem" means United Coconut Chemicals, Inc., and its successors or
assignees;
"Cogeneration Power Production Facility" means a combined cycle
cogenerating plant and all other facilities built or to be built in respect
thereof by SPCC to enable SPCC to fulfill its obligations under this
Agreement, including the Switchyard Facilities;
"Commercial Operation Date" means subject to the Cogeneration Power
Production Facility having otherwise been built in accordance with this
Agreement, the date on which SPCC and NPC jointly certify (NPC's
certification not to be unreasonably withheld) that the Cogeneration Power
Production Facility is capable of operating in accordance with the
Operating Parameters set forth in the Second Schedule and has successfully
completed the Guarantee Test in accordance with the Fourteenth Schedule,
but not before the Target Commercial Operation Date;
"Competent Authority" means:
(a) the Departments of Energy, Environment and Natural Resources, Finance
and Justice of the Government of the Republic of the Philippines, the
National Electrification Administration, Energy Regulatory Board,
National Economic and Development Authority, Board of Investments and
Regional Development Council of the Republic of the Philippines,
Bangko Sentral ng Pilipinas, Bureau of Internal Revenue, and the
relevant Barangay, Municipal and Provincial Councils; and
(b) the Government of the Republic of the Philippines or of any
subdivision thereof and any other minister or governmental, quasi-
governmental, electricity supply industry or other regulatory
department, body, instrumentality, agency or authority of the Republic
of the Philippines or of any subdivision thereof having jurisdiction
over this Agreement, a Party or any asset or transaction mentioned in
or contemplated by this Agreement;
"Consent" means any permission, license, authority, approval,
certification, registration, exemption or consent of any Competent
Authority (including advice that there is no objection to a particular
proposal or that a particular proposal is not inconsistent with the policy
or guidelines of any Competent Authority) and, where a Competent Authority
is authorized to prohibit a proposal, the passing of the time limited for
such prohibition without the proposal being prohibited;
"Contract Signing Date" means the date this Agreement is executed by
the Parties;
"Contract Year" means a period of one Year commencing on the first day of
the Cooperation Period or any anniversary thereof; provided that the last
Contract Year shall end upon termination of this Agreement;
4
<PAGE>
"Contracted Capacity" or "CC" means 304 MW of total net generating capacity
on a continuous and reliable basis, measured at the Delivery Point with all
GTGs and the STG operating in a steady state condition at the Site,
adjusted to Ambient Conditions while delivering steam to the Thermal Hosts;
"Cooperation Period" means the period commencing on the Commercial
Operation Date and ending on the date twenty-five (25) Years thereafter
(unless earlier terminated pursuant to this Agreement);
"Day" means calendar day, commencing at 12:00:01 a.m. Manila time, and
ending at 12:00:00 a.m. Manila time;
"Deemed Completion Date" has the meaning ascribed thereto in Article
4.7.1;
"Delivery Point" means the metering point on the 230 kV side of the main
transformer(s) referred to in the Seventh Schedule (Measurement and
Recording of Electricity);
"Emergency" means a failure in the continuous supply of electricity to the
grid after the Commercial Operation Date which reasonably requires NPC to
request SPCC to supply it with power as soon as possible;
"Energy Fees" or "EF" has the meaning ascribed thereto in the Eighth
Schedule;
"Energy Report" means the reports submitted in accordance with the Eighth
Schedule with the Department of Energy reporting energy input (fuel) to the
Cogeneration Power Production Facility and energy outputs (steam,
electricity) from the Cogeneration Power Production Facility;
"Environmental Compliance Certificate" or "ECC" means the certification
issued by the Department of Environment and Natural Resources of the
Republic of the Philippines (or any governmental authority which succeeds
to the functions thereof) for the Cogeneration Power Production Facility;
"Expert" means a party appointed pursuant to Article 14 to resolve
technical disputes related to the Project;
"Financial Closing" has the meaning ascribed to it in Article 3.1.1.2;
"Fixed Operating and Maintenance Fees" or "FOMF" has the meaning ascribed
to it in the Eighth Schedule;
"Force Majeure" has the meaning ascribed to it in Article 13.1;
"Forced Outage" has the meaning ascribed to it in the Sixth Schedule
(Electricity Delivery Procedures);
"Foreign Component" means that portion of the Fixed Operating and
Maintenance Fees and the Energy Fees, calculated on the basis of U.S.
Indices;
"Fuel" means Low Sulfur Waxy Residual Oil ("LSWR") or such other fuel as
shall be agreed between NPC and SPCC used for running the Cogeneration
Power
5
<PAGE>
Production Facility which meets the Specifications set forth in the
Fourth Schedule or such other specifications as shall be agreed between NPC
and SPCC;
"Fuel Fees" has the meaning ascribed to it in the Eighth Schedule (Delivery
of Power and Energy);
"Generating Assets" has the meaning ascribed to it in the First Schedule
(Project Scope and Specifications), Article VI;
"Good Operating Procedures" means the relevant practices, procedures and
methods generally applied in or approved by the international electric
power supply industry in the course of operating and maintaining private
power generation systems that, at any particular time, in the exercise of
reasonable judgment in the light of the facts which are known or which
reasonably could have been known at the time a decision is made, would be
expected to accomplish the desired result in a manner consistent with
safety, Law, reliability, environmental protection, economy and expedition;
Good Operating Procedures may evolve over time but generally modified
procedures, practices and methods shall be applied only with prospective
effect and as shall be appropriate for a power station of the age and
condition of the Cogeneration Power Production Facility;
"Government Force Majeure" has the meaning ascribed to it in Article 13;
"Grid Code" means the embodiment of the rules governing the operation,
maintenance and development of the power transmission network;
"GTG" means Combustion Turbine Generator;
"Guaranteed Heat Rate" or "GHR" means 7160 Btu/kWh, representing the fuel
heat input required to generate a kWh (measured at the high voltage side of
the main transformer) , upon which the Cogeneration Power Production
Facility's Fuel Fees are calculated for MW capacities delivered equal to or
greater than 200 MW, below which a different Guaranteed Heat Rate shall
apply as provided for in the Eighth Schedule and the Ninth Schedule;
"Guarantee Test" has the meaning ascribed to it in the Fourteenth Schedule;
"Internationally Accepted Engineering Standards" means those practices,
methods and acts set forth in the First Schedule (Project Scope and
Specifications);
"Industrial Rate" means the latest published schedule setting forth the
energy and demand charge made by NPC to its industrial users adjusted from
time to time in accordance with NPC's applicable automatic power cost
adjustment factors;
"Law" means all laws, ordinances, statutes, rules, orders, decrees,
injunctions, international agreements and regulations of law in the
Republic of the Philippines or any other Competent Authority, and any and
all Consents;
"Lender" means a bank, financial institution or other entity which provides
loans or other financing to SPCC for the construction, operation and/or
maintenance of the Cogeneration Power Production Facility under a Lending
Agreement, and its successors or assigns;
6
<PAGE>
"Lending Agreement" means a loan agreement, note, bond, indenture, security
agreement, swap agreement or any other instrument relating to the financing
or refinancing of the construction, operation and/or maintenance of the
Cogeneration Power Production Facility;
"Local Component" means that portion of the Fixed Operating and Maintenance
Fees and Energy Fees calculated on the basis of Philippine Indices;
"Milestone" means each of the activities listed in Article 3.1 hereof;
"NEDA" means the National Economic and Development Authority of the
Republic of the Philippines or any governmental authority which succeeds to
the functions thereof;
"Net Available Capacity" means the actual net generating capacity of the
Cogeneration Power Production Facility (expressed in kW) measured at the
Delivery Point when all GTG's and the STG are operating in a steady state
condition at the Site adjusted to Ambient Conditions, demonstrated by the
Performance Test nominated by SPCC in respect of a Contract Year or part
thereof. This value shall be adjusted to account for capacity degradation
due to site ambient conditions (temperature other than 32 degrees
Centigrade) as per vendor furnished data and/or curves;
"Operating Parameters" means the operating parameters of the Cogeneration
Power Production Facility described in the Second Schedule (Operating
Parameters);
"Party" means either NPC or SPCC and "Parties" means both NPC and SPCC;
"Performance Tests" has the meaning ascribed to it in the Fourteenth
Schedule (Tests and Test Procedures);
"Performance Undertaking" means the agreements substantially in the form
set out in the Eleventh Schedule: Exhibit A (Agreement as to Fundamental
Rights), Exhibit B (Guarantee of Project Agreements) and Exhibit C (Foreign
Exchange Convertibility Agreement);
"Philippine Indices" means the indices utilized in the calculation of the
Adjustment Factor (P) pursuant to the Eighth Schedule (Delivery of Power
and Energy);
"Pioneer Status" means the status conferred by the Board of Investments of
the Republic of the Philippines (or any governmental authority which
succeeds to the functions thereof), evidenced by a Certificate of
Registration in relation to the development, construction, operation and
maintenance of the Cogeneration Power Production Facility confirming that
SPCC is a registered pioneer enterprise under the Omnibus Investments Code
of 1987;
"Project" means the design, financing, construction, equipping, completion,
testing, commissioning, operation and maintenance of the Cogeneration Power
Production Facility and associated Switchyard Facilities at the Refinery,
accredited by the Department of Energy of the Republic of the Philippines
and
7
<PAGE>
capable of delivering reliable electrical power to NPC and of delivering
reliable steam to the Thermal Hosts;
"Proponents" means the persons mentioned in the ninth Recital;
"Proponents' Agreement" means the agreement between NPC and the Proponents
substantially in the form set out in the Twenty-First Schedule;
"Refinery" means the refinery owned by Caltex located in Batangas Province,
the Republic of the Philippines as more fully described in the First
Schedule (Project Scope and Specifications);
"San Pascual Cogeneration Company International B.V." or "SPCC" means the
Netherlands corporation formed by special purpose subsidiaries of Texaco
Inc. and Edison Mission Energy for the purpose of developing and signing
this Agreement;
"San Pascual Cogeneration Company" or "SPCC Philippines" means the
Philippine limited partnership formed by Batangas Energy Corporation, a
wholly owned subsidiary of Caltex, and SPCC for the purpose of undertaking
certain responsibilities in relation to the Project pursuant to the Twelfth
Schedule;
"Shareholders" means, with respect to SPCC, the shareholders in SPCC from
time to time; and, with respect to SPCC Philippines, the partners in SPCC
Philippines from time to time;
"Site" means the site of the Cogeneration Power Production Facility as more
particularly described in the First Schedule (Project Scope and
Specifications);
"Specifications" means the specifications of the Cogeneration Power
Production Facility described in the First Schedule (Project Scope and
Specifications);
"Steam Assets" means the equipment primarily used in the generation of
steam as more definitively stated in the First Schedule (Project Scope and
Specifications) Article VII;
"STG" means Steam Turbine Generator;
"Switchyard Facilities" means those Facilities necessary to interconnect
the Cogeneration Power Production Facility with NPC's grid including the
switch yard, protective relays, protection control equipment,
communications facilities and other related equipment as more fully
described in the First Schedule;
"Target Commercial Operation Date" means that date which is set forth in
Article 3.1 as the same may be extended from time to time pursuant to this
Agreement;
"Target Transmission Line Completion Date" means the date which is forty
(40) Calendar Months after the Contract Signing Date;
"Test" means any test of the Cogeneration Power Production Facility (or any
part thereof, wherever situated and whether or not then incorporated
therein) required by the Fourteenth Schedule or otherwise by this
Agreement, and, unless the
8
<PAGE>
context otherwise requires, the test procedure, test documentation,
criteria of satisfaction, procedures, standards, protective settings,
duration and programme;
"Thermal Efficiency Standards" means those standards set forth in SPCC's
Department of Energy Certificate of Accreditation;
"Thermal Hosts" shall mean Caltex, Cocochem, and any other entities
purchasing steam from SPCC;
"Transmission Line" means the transmission line and other related equipment
described in the Fifth Schedule (Transmission Line Specifications);
"Transmission Line Completion Date" means that date upon which the
Transmission Line is capable of supplying start up power and allowing the
Cogeneration Power Production Facility to operate in parallel to NPC's grid
at its Contracted Capacity but not before the Target Transmission Line
Completion Date unless the parties otherwise agree;
"U.S. Indices" means the indices utilized in the calculation of the
Adjustment Factor (US$) pursuant to the Eighth Schedule; and
"Year" means a period of one year according to the Gregorian calendar
commencing on any day of a year.
1.2 HEADINGS. As used herein, headings are for convenience and do not
---------
form part of, and shall not affect the interpretation of, this Agreement.
1.3 INTERPRETATION. In this Agreement, unless the context otherwise
---------------
requires:
(a) the singular includes the plural and vice versa;
(b) any gender includes the other;
(c) reference to a statute, by-law, regulation, rule, delegated
legislation or order is to the same as amended, modified or replaced
from time to time and to any by-law, regulation, rule, delegated
legislation or order made thereunder;
(d) reference to a Consent is to the same as amended, modified or replaced
from time to time, and to any proper order, instruction, requirement
or decision of any Competent Authority thereunder;
(e) reference to an agreement or instrument is to the same as amended,
novated, modified or replaced from time to time;
(f) reference to a Party is to a Party to this Agreement, its successors
and permitted assigns;
(g) reference to a Recital, Article, or Schedule is to a recital, article,
or schedule of or to this Agreement;
(h) reference to "above" or "below" is to the first occurrence above or
below the reference;
9
<PAGE>
(i) reference to a document or agreement in the "agreed form" is to a
document or agreement in the form and terms agreed by the parties;
(j) where a word or expression is defined, cognate words and expressions
shall be construed accordingly;
(k) "including" shall not be construed as being by way of limitation and
"otherwise" shall not be construed as limited by words with which it
is associated;
(l) any reference to a governmental ministry, department, authority or
agency shall be construed as being to any governmental ministry,
department, authority, or agency which succeeds to the functions
thereof;
(m) the word "reasonable" appearing before "approval", "consent",
"satisfaction" or any similar word shall mean that the approval,
consent, expression of satisfaction or other decision to be made as to
the particular matter or thing concerned shall not unreasonably be
withheld or delayed. Conversely, if the word "reasonable" does not so
appear, the approval, consent, expression of satisfaction or other
decision to be made may be given or made solely at the unfettered
discretion of the Party concerned; and
(n) the expression "to the best of its knowledge" shall mean to the best
of the knowledge and belief of the Party concerned, having made all
due and reasonable inquiry.
1.4 ABBREVIATIONS. In this Agreement:
--------------
(a) "US$" and "Dollar(s)" denote lawful currency of the United States of
America;
(b) "Ps", "PHP" and "Peso(s)" denote lawful currency of the Republic of
the Philippines;
(c) "MW" denotes a megawatt;
(d) "kW" denotes a kilowatt;
(e) "kWh" or "KWHR" denotes a kilowatt hour;
(f) "kW-Month" denotes a kilowatt month;
(g) "kV" denotes a kilovolt;
(h) "kVA" denotes a Kilovolt-ampere;
(i) "Btu" denotes a British Thermal Unit; and
(j) "mmBtu" denotes a million British Thermal Units.
10
<PAGE>
ARTICLE 2 - SCOPE OF AGREEMENT
2.1 THE COGENERATION POWER PRODUCTION FACILITY. SPCC shall cause and be
------------------------------------------
responsible for the financing, design, development, permitting, site
survey, development and investigation, construction, completion, testing,
commissioning, operation and maintenance of the Cogeneration Power
Production Facility and Switchyard Facilities in accordance with the First
(Project Scope and Specifications), Second (Operating Parameters), Sixth
(Electricity Delivery Procedures), Fourteenth (Tests and Test Procedures)
and Sixteenth (Environmental Criteria) Schedules and otherwise as provided
in this Agreement at its cost, expense and risk (except as otherwise
provided in this Agreement) and so that:
(a) the Commercial Operation Date occurs on the Target Commercial
Operation Date;
(b) Contracted Capacity, Net Electrical Output and Ancillary Services are
supplied to NPC at the Delivery Point during the Cooperation Period;
and
(c) Plant overall annual thermal efficiency is not less than 60%.
Notwithstanding the foregoing, the only consequence to SPCC should the Net
Available Capacity be less than the Contracted Capacity shall be the
penalties calculated pursuant to the Eighth Schedule.
2.2 CONSTRUCTION. The Cogeneration Power Production Facility and Switchyard
------------
Facilities shall be constructed and equipped in accordance with the First
Schedule (Project Scope and Specifications).
2.3 COST OF CONSTRUCTION. Except as otherwise set forth in this Agreement, all
--------------------
costs of SPCC in the performance of its obligations in connection with the
construction of the Cogeneration Power Production Facility as provided in
Articles 2.1 and 2.2 shall be borne by SPCC. All necessary funding
including any available preferential credits shall be arranged by and be
the responsibility of SPCC.
2.4 THE SITE. Locating, acquiring and developing the Site shall be the
--------
responsibility of, and for the account of SPCC.
2.5 CONSENTS. SPCC shall at all material times obtain, maintain and comply
--------
with the terms of all Consents required to be obtained by it to fulfill its
obligations under this Agreement.
2.6 SUPPLY OF ELECTRICITY. NPC shall, subject to relevant regulations,
---------------------
endeavor to supply electricity to SPCC at such times and in such quantities
as SPCC may from time to time reasonably request on reasonable notice to
NPC and shall be paid for by SPCC at the Industrial Rate, or such
substitute rate as shall be approved by the Energy Regulatory Board, for
the purposes set forth below:
2.6.1 During Construction: SPCC shall be responsible to tie in to NPC's
-------------------
grid system at the nearest source of supply to the Site;
11
<PAGE>
2.6.2 During Start-up: At the Delivery Point specified in the Seventh
---------------
Schedule for:
(a) the no load test prior to the initial synchronization of the
GTGs and/or the Cogeneration Power Production Facility;
(b) testing and commissioning after initial synchronization up to
the Commercial Operation Date;
(c) the start up of each gas turbine and the Cogeneration Power
Production Facility from time to time during the period from
the Commercial Operation Date and throughout the Cooperation
Period;
2.6.3 During and after Plant Outages: At the Delivery Point to operate
------------------------------
the Cogeneration Power Production Facility equipment necessary
during outages and to re-start the Cogeneration Power Production
Facility after such outages as requested by SPCC;
2.6.4 During the Cooperation Period: At the Delivery Point to supply the
------------------------------
general power requirements of the Cogeneration Power Production
Facility (including electricity for housing, lighting, air
conditioning and water supply), when the Cogeneration Power
Production Facility is not operating;
2.6.5 Start-ups.
---------
2.6.5.1 Start-ups Following Certain Shutdowns: Notwithstanding the
-------------------------------------
foregoing subsections of this Article 2.6, all electricity
taken by SPCC for the GTG load test or GTG start-ups
following a shutdown (a) pursuant to a dispatch order of
NPC which is not the result of any failure of SPCC to
comply with its obligations under this Agreement (whether
or not as a result of Force Majeure) affecting NPC; or (b)
as a result of any failure of NPC to comply with its
obligations under this Agreement (except to the extent
occasioned by Force Majeure, other than Government Force
Majeure) but not pursuant to a dispatch order of NPC; shall
be for the account of NPC.
2.6.5.2 Black Start Capability: The Cogeneration Power Production
----------------------
Facility shall have a Black Start capability; provided,
however, that SPCC may from time to time, in its
discretion, utilize power from the Thermal Hosts to start
up the Cogeneration Power Production Facility instead of
relying on its internal Black Start capability.
2.7 TRANSMISSION LINE. NPC shall construct the Transmission Line in accordance
------------------
with the Fifth Schedule and otherwise as required by this Agreement to
interconnect the Cogeneration Power Production Facility to NPC grid system
at its cost, expense and risk (except as otherwise set forth in this
Agreement) so that the Transmission Line Completion Date occurs not later
than the Target Transmission Line Completion Date.
12
<PAGE>
2.8 OPERATION. As more fully set forth in Article 5, SPCC shall, at its cost,
----------
expense and risk (except as otherwise required by this Agreement), operate
the Cogeneration Power Production Facility during the Cooperation Period
within the Operating Parameters set out in the Second Schedule (Operating
Parameters) and in accordance with Good Operating Procedures, and the
dispatch instructions of NPC properly given according to the Sixth
Schedule. NPC shall have the right, subject to the conditions set forth in
the Sixth Schedule, to dispatch the Cogeneration Power Production Facility
to an output of 90 MW. Notwithstanding anything to the contrary set forth
in this Agreement, to the extent that the Cogeneration Power Production
Facility is operating at a reduced output pursuant to NPC's dispatch
instructions below 200 MW, SPCC shall be entitled to operate the
Cogeneration Power Production Facility at less than 60% thermal efficiency,
and shall not be subject to any penalties for failure to meet the Thermal
Efficiency Standards.
2.9 POWER AND ENERGY. As more fully set forth in Articles 5 and 6:
-----------------
2.9.1 SPCC shall, at its cost, expense and risk (except as otherwise set
forth in this Agreement) deliver the Net Available Capacity and
energy to NPC at the Delivery Point during the Cooperation Period.
2.9.2 SPCC shall provide Ancillary Services to NPC during the Cooperation
Period.
2.9.3 NPC shall take the Net Available Capacity and energy delivered by
the Cogeneration Power Production Facility at the Delivery Point on
the outgoing line and shall pay to SPCC fees as provided in Part B
of Article 6.
2.9.4 SPCC shall have the right to provide emergency power supply to the
Thermal Hosts upon clearance from NPC Systems Operations; provided,
however, that SPCC shall install meters to monitor such deliveries
and NPC shall have the right to invoice the Thermal Hosts, at its
normal energy rates (less any standby or demand charges) for
deliveries of power from the Cogeneration Power Production Facility.
Such power shall be included in the calculation of Energy Fees and
Fuel Fees in accordance with Article 6 hereof. Except as set forth
herein, SPCC shall not confer upon any other person a right to
electricity generated by the Cogeneration Power Production Facility.
2.10 STEAM. During the Cooperation Period, SPCC shall deliver steam to the
------
Thermal Hosts in accordance with the terms and conditions of the agreements
with the Thermal Hosts. Any failure to deliver steam which results in SPCC
failing to meet the Thermal Efficiency Standards shall result to a penalty
to SPCC as more fully set out in the Eighth Schedule if not excused under
Article 2.8 above.
2.11 COSTS OF NPC. NPC shall be responsible for and shall bear all costs
------------
incurred by it in connection with the performance of its obligations under
this Agreement.
2.12 OWNERSHIP OF COGENERATION POWER PRODUCTION FACILITY. Subject only to
----------------------------------------------------
Article 18, SPCC shall at all times own the Cogeneration Power Production
Facility including all equipment and materials on the Site or used in
13
<PAGE>
connection with the Cogeneration Power Production Facility and Switchyard
Facilities which have been supplied by it or at its cost.
2.13 CERTAIN RESPONSIBILITIES OF SPCC. On and subject to the terms of this
---------------------------------
Agreement, SPCC, at its own cost, shall be responsible for:
(a) acquiring and developing the Site, construction, erection of the
required infrastructure as described in Articles 3 and 4 of the First
Schedule (Project Scope and Specifications);
(b) importing and transporting equipment to the Site;
(c) obtaining permits for the building, construction, operation and other
permits to form the basis of SPCC's application for an Environmental
Compliance Certificate; Regional Development Council, Barangay,
municipal and provincial resolutions, licenses and business permits
and approvals for the Project; and visas and work permits for foreign
personnel; recruiting local labor; and complying with all local and
other regulations, including the payment of all fees and costs thereof
(other than those which are to be obtained by NPC pursuant to this
Agreement);
(d) constructing the Cogeneration Power Production Facility and Switchyard
Facilities in accordance with the specifications set out in the First
Schedule (Project Scope and Specifications) and Sixteenth Schedule
(Environmental Criteria) and in compliance with the requirements of
the Environmental Compliance Certificate;
(e) preparing the Environmental Impact Statement Report (including the
Environmental Impact Study) and obtaining the Project's Environmental
Compliance Certificate; and
(f) supplying and delivering Fuel necessary to generate electricity
required pursuant to Article 6.1, or causing such Fuel to be supplied
and delivered, during the period from the testing and commissioning of
the Cogeneration Power Production Facility and during the Cooperation
Period.
2.14 CERTAIN RESPONSIBILITIES OF NPC. On and subject to the terms of this
--------------------------------
Agreement, NPC shall:
(a) cooperate with and provide SPCC with any available data or information
needed for SPCC to obtain an Environmental Impact Assessment report
which are necessary for SPCC to obtain an Environmental Compliance
Certificate;
(b) provide SPCC with technical information required by SPCC for the
design of the Switchyard and associated facilities; and
(c) on a best efforts basis, provide the required endorsements where
reasonably necessary, for SPCC to obtain the government approvals
described in Articles 2.13(c) and 28.1.2.
2.15 MUTUAL COOPERATION. The Parties shall mutually cooperate with each other in
-------------------
order to achieve the objectives of this Agreement.
14
<PAGE>
2.16 FUEL SUPPLY. SPCC shall, at its cost, expense and risk (except as
------------
otherwise provided in this Agreement), supply and deliver all Fuel required
during the start-up testing, commissioning of the Cogeneration Power
Production Facility and all fuel required in the operation of the
Cogeneration Power Production Facility during the Cooperation Period.
ARTICLE 3 - CONSTRUCTION
3.1 PROJECT MILESTONE DATES.
------------------------
3.1.1 SPCC shall commence development of the Cogeneration Power Production
Facility on the Contract Signing Date and shall thereafter
diligently pursue such work in order to achieve the timely
completion of the Project and fulfill its other obligations under
this Agreement in accordance within the following timetable:
<TABLE>
<CAPTION>
MILESTONE TARGET DATE
(Months from Contract
Signing Date)
<S> <C>
Posting of Development Bond within ten Days
Completion of Documentary requirements Six (6) Calendar Months
(Government Approvals)
Issuance of Environmental Compliance Ten (10) Calendar Months
Certificate
Financial Closing Date Fifteen (15) Calendar Months
Site/Project Mobilization Date Sixteen (16) Calendar Months
Target Commercial Operation Date Forty-Four (44) Calendar Months
Posting of O & M Bond within ten Days after Commercial
Operation Date
</TABLE>
3.1.1.1 Environmental Compliance Certificate issuance shall be the
time at which SPCC Philippines has received such issuance
from the Department of Environmental and Natural Resources,
and has provided NPC a copy thereof, as certified by an
appropriate officer of SPCC Philippines.
3.1.1.2 Financial Closing shall be the time at which SPCC has
demonstrated, to the reasonable satisfaction of NPC, that
the financial resources committed to SPCC are adequate to
perform SPCC's obligations under this Agreement by
submitting a confirmation from its Lenders to NPC that the
initial drawdown of
15
<PAGE>
funds under the Lending Agreements is subject to no further
condition.
3.1.1.3 Site/Project Mobilization shall be the time at which (a)
SPCC begins, and thereafter diligently continues,
construction of the foundation footings or other similar
work which demonstrates, to the reasonable satisfaction of
NPC, that it has begun (and intends diligently to pursue)
construction of the Cogeneration Power Production Facility
on the Site; and (b) SPCC delivers the Construction
Performance Bond (Eighteenth Schedule) to NPC.
3.1.1.4 Within ten (10) Days after the Commercial Operation Date,
SPCC shall deliver the O & M Bond (Nineteenth Schedule) to
NPC. Notwithstanding anything to the contrary elsewhere
contained in this Agreement, the Commercial Operation Date
shall not occur until SPCC has so delivered that O & M
Bond, and the Commercial Operation Date shall not occur
prior to the Target Commercial Operation Date.
3.1.2 If a Party is prevented, hindered or delayed in the performance of
an obligation under this Agreement by:
(a) Force Majeure; or
(b) by any failure (whether or not occasioned by Force Majeure) of
the other Party to perform an obligation under this Agreement
(including, in the case of NPC, to take electricity);
then, unless specifically provided otherwise in this Agreement, the
time limited for the performance of that obligation (or any date by
which performance of that obligation is to be achieved, including in
the case of SPCC, the Target Commercial Operation Date, and in the
case of NPC, the Target Transmission Line Completion Date) shall at
the option of the affected Party be extended by a period equal to
the period by which its performance is so prevented, hindered or
delayed. However, the time limited for performance of an obligation
by NPC shall not be extended to the extent that performance of that
obligation is prevented, hindered or delayed by Government Force
Majeure.
3.1.3 NPC shall defend, indemnify and hold SPCC harmless against any and
all claims and demands for any liabilities (other than contractual
liabilities to the Thermal Hosts) and damages and all reasonable
costs payable to any third parties as a result of the extension of
the target date for any Milestone for reasons other than (i) the
fault of SPCC; or (ii) any event of Force Majeure (other than
Government Force Majeure). The Parties shall consult with each other
and take all reasonable steps to minimize the losses of either Party
from any such delay and to minimize any overall delay or prejudice
to the Project. NPC or the appropriate governmental authority shall
have the right to audit all costs charged to NPC by SPCC pursuant to
this Article 3.1.3.
3.1.4 Notwithstanding anything to the contrary contained in this
Agreement, NPC shall not draw on the Development Bond for any delay
or failure in
16
<PAGE>
performance by SPCC hereunder if the Environmental Compliance
Certificate is delayed or not issued and such delay or non-issuance
is attributable to the action or inaction of NPC or any relevant
Competent Authority and not to any failure of SPCC to submit
required documents or otherwise fulfill the legal requirements for
issuance of an Environmental Compliance Certificate.
3.2 DELAY IN ACHIEVING MILESTONE
----------------------------
3.2.1 If, subject to Article 3.1.2, SPCC fails to achieve a Milestone by
the date therefor, it shall pay to NPC the amounts and at the times
mentioned, and at the rate set forth in respect of such delay in the
Third Schedule, for each Day of delay thereafter until such
Milestone is achieved.
3.2.2 In the case of the amounts paid before the Commercial Operation
Date, NPC shall refund such amounts paid by SPCC, without interest,
if the Commercial Operation Date occurs on or before the Target
Commercial Operation Date. SPCC acknowledges that this is a
reasonable security required by NPC in the light of its
responsibilities, and reflects the possibility that the Commercial
Operation Date will not occur by the Target Commercial Operation
Date and that electricity from the Cogeneration Power Production
Facility will not be available to it on that date; and in the case
of the non-delivery of the O & M Bond, that NPC will not have
security for the performance of SPCC's obligations after the
Commercial Operation Date.
3.3 SPCC'S RIGHTS. Pursuant to its obligations under Article 3.1 SPCC shall,
--------------
among other things, have full right to:
(a) call for tenders and award contracts with or without tender;
(b) arrange for the preparation of detailed designs and approve or reject
the same;
(c) appoint and remove consultants and professional advisers;
(d) purchase equipment;
(e) appoint, organize and direct staff, and manage and supervise the
Project;
(f) enter into contracts for the supply of materials and services; and
(g) do all other things necessary or desirable for the completion of the
Facilities in accordance with the Specifications and Internationally
Accepted Engineering Standards by the Target Commercial Operation
Date.
3.4 LOCAL CONTRACTS. In fulfilling its obligations under Article 3.1 SPCC
----------------
shall, where available, award contracts to Philippine contractors and suppliers
of materials and services provided that the quality, delivery times, costs,
reliability and other terms are comparable to those offered by non-Philippine
contractors and/or suppliers.
17
<PAGE>
3.5 MONITOR PROGRESS.
-----------------
(a) NPC shall review the basic engineering designs and plans prepared by
SPCC for the Cogeneration Power Production Facility and the detailed
designs of the Switchyard Facility in terms of its compliance with the
prescribed standards and specifications set forth in the First
Schedule; to ensure that the design and plans will not adversely
affect the safe and secure operation of the grid, and shall approve
the same, if found acceptable, prior to actual construction. NPC shall
not unreasonably withhold such approval if design is per prescribed
standards and specifications and within Internationally Accepted
Engineering Standards. Any design changes by NPC outside of the
prescribed standards and specifications are subject to concurrence by
SPCC and, when applicable, are subject to a change in Capital Recovery
Fees and in the schedule unless it is shown to SPCC's reasonable
satisfaction that the safety or integrity of the grid would be
compromised if such changes were not implemented. If NPC has not
commented on such designs or plans within seventeen (17) Days from the
date of receipt by NPC per the drawing submittal schedule agreed
between NPC and SPCC, then such designs and plans shall be deemed
approved. This approval by NPC notwithstanding, SPCC shall be solely
responsible for the integrity of its detailed engineering designs and
plans. The approval thereof by NPC does not diminish this
responsibility, nor does it transfer any part of such responsibility
to NPC.
(b) SPCC shall allow NPC to conduct environmental audits and monitoring in
accordance with the Environmental Compliance Certificate. During such
audit and monitoring, NPC personnel shall be accompanied at all times
by SPCC personnel, and shall be subject to Site rules and regulations.
Such audits shall be limited to SPCC'S battery limits.
(c) NPC shall be entitled, at its own cost, to monitor the progress and
quality of the design, construction and installation work and for this
purpose SPCC shall:
(i) submit to NPC a monthly report (in form and content reasonably
satisfactory to NPC), due within thirty (30) Days from the end
of the preceding month, outlining the construction progress in
such detail as is reasonable in the circumstances;
(ii) ensure that NPC and any experts appointed by NPC in connection
with the Project, with reasonable notice, are afforded
reasonable access to the Site at times to be agreed with SPCC,
provided that such access does not interfere with the work
comprising the Project or expose any person on the Site to any
danger;
(iii) make available to NPC and any experts appointed by NPC in
connection with the Project for inspection at the Site copies
of all plans and designs (other than any proprietary
information of SPCC or any of its contractors) or any part
thereof; including all design drawings of SPCC or of its
contractor or sub-contractor and manufacturers' engineering and
technical manuals; and
18
<PAGE>
(iv) make available an office of approximately 150 square feet at
the Site for the use of NPC personnel performing such
monitoring.
(d) NPC shall be entitled at its own cost to witness Tests of machinery at
the Site. SPCC shall give NPC fourteen (14) Days' written notice of
the initiation of such Tests. Revision to the initiation of such Tests
shall be given verbally no less than twenty four hours in advance to
be followed by a written confirmation.
(e) As soon as practicable after this Agreement is signed, NPC and SPCC
shall organize a committee to formulate and agree on procedures for
monitoring and reviewing the progress of the design, construction,
equipping, completion and commissioning of the Cogeneration Power
Production Facility and the Switchyard Facility.
3.6 DISCLAIMER.
----------
SPCC:
(a) accepts that any information made available to NPC and any comment or
approval made or given by NPC in respect thereof or otherwise in
respect of the construction, operation and maintenance of the
Cogeneration Power Production Facility (including the certification of
the results of Tests) shall not relieve SPCC of any obligation nor
prejudice any right of NPC under this Agreement;
(b) shall in no way represent to any third party that, as a result of any
engineering review conducted by NPC, NPC is responsible for the
engineering soundness of, or otherwise makes any representation or
warranty as to, the Cogeneration Power Production Facility;
(c) agrees that it shall, subject to the other provisions of this
Agreement, be solely responsible for the economic and technical
feasibility, operational capability and reliability of the
Cogeneration Power Production Facility; and
NPC and SPCC acknowledge that Article 3.5 is intended to provide NPC the
right to gather data for its own information only, and that, except as
specifically set forth in Article 3.5(a), the same shall not be construed
as giving NPC the right to approve, consider for possible amendment,
require any revision or take any action with respect to designs or other
works on the Facilities, provided, the design and works will not adversely
affect the NPC grid, are as per prescribed standards and specifications,
and are within Internationally Accepted Engineering Standards.
3.7 CONSULTATION. SPCC shall consult with NPC before and during the development
-------------
of the design of the Cogeneration Power Production Facility and Switchyard
Facility and, if and to the extent that operation of the grid may be
affected, will discuss with NPC the possibility of alterations to the
Specifications.
3.8 DRAWINGS AND TECHNICAL DETAILS. Without prejudice to Article 3.5, SPCC
------------------------------
shall, prior to commencing actual construction of the Cogeneration Power
Production Facility and Switchyard Facility, prepare and submit to NPC five
(5)
19
<PAGE>
hard copies regarding the main group of drawings and technical details
listed hereunder with respect to the Generating Assets:
(a) final arrangement plans for general layout of machinery and equipment;
(b) general and detailed drawings and specifications for electro-
mechanical work;
(c) general and detailed design drawings for civil and architectural
works;
(d) electrical protection drawings;
(e) generator protection drawings;
(f) GTG and STG turbine output curves;
(g) energy balance calculation;
(h) electrical single line diagram;
(i) systems flow diagrams;
(j) project summary comprising a general plant description, thermal
process, electrical concept, control and monitoring concept, operating
concept and general layout;
(k) definitive overall project schedule; and
(l) technical data such as design condition and assumptions of plant data,
performance data of equipment(s), and correction curves.
As soon as practicable or within six (6) months after the Commercial
Operation Date, SPCC shall furnish NPC three (3) copies of "as-built" plans
and design drawings in ISO 44 size (bound) and operation and maintenance
manuals. Thereafter, SPCC shall furnish NPC any revisions thereof from the
"as built" plans and design drawings during the Cooperation Period in the
same number of copies and ISO 44 size. "As-built" plans and design drawings
shall also be provided on microfilm or in such other electronic medium as
SPCC and NPC may agree.
3.9 CONFIDENTIALITY.
----------------
(a) During the term of this Agreement each Party shall treat as
confidential and (except as provided in Article 3.9(b)) shall not
without first obtaining the consent of the other Party disclose to any
person the provisions of this Agreement or any information supplied or
made available for examination or otherwise disclosed hereunder to
such Party by the other (such provisions and, in relation to such
Party, such information being hereinafter referred to as "Confidential
Information").
(b) Notwithstanding the provisions of Article 3.9(a), Confidential
Information may be disclosed without the other Party's consent:
20
<PAGE>
(i) by a Party to a governmental department, agency or authority;
(ii) by SPCC to the Lenders;
(iii) by a Party to its directors, officers, employees, agents and
technical and professional advisers (and those of its parent
companies and/or their subsidiary companies) who reasonably
require such information in the course of their duties and
responsibilities in relation to this Agreement;
(iv) by a Party to its contractors and suppliers to the extent they
reasonably require such information in the performance of their
obligations in relation to this Agreement;
(v) by a Party to the extent reasonably required for the purposes
of obtaining and maintaining insurance;
(vi) to the extent required by law, the rules of any recognized
stock exchange upon which the shares of the disclosing Party
(or of its parent companies or its and/or their subsidiary
companies) are listed;
(vii) for the purposes of dispute resolution or the enforcement of
rights and obligations under this Agreement; and
(viii) to the extent such information has become generally available
to the public other than as a result of a breach by the
disclosing Party of its obligations under this Article 3.9.
3.10 BOND.
----
(a) To secure the performance of its obligations under Article 3.2 in
respect of the Development Milestones, SPCC shall, not later than ten
(10) Days from the Contract Signing Date, cause to be issued and
delivered to NPC, and maintained in full force and effect until the
start of the Site/Project Mobilization, a standby letter of credit
confirmed by a local bank in favor of NPC (the "Development Bond") in
the agreed form in an amount equal to thirty (30) US$ multiplied by
the Contracted Capacity (expressed in Kilowatts) (US$9,120,000.00).
The form of the Development Bond is attached hereto as the Seventeenth
Schedule. If the letter of credit is not so issued and delivered, this
Agreement shall immediately terminate and be of no force or effect.
(b) To secure the performance of its obligations under Article 3.2 in
respect of the Construction Milestones, and to secure NPC against an
Abandonment by SPCC of the Cogeneration Power Production Facility
during construction, SPCC shall, upon the achievement of Site/Project
Mobilization, promptly cause to be issued and delivered to NPC, and
maintained in full force and effect until the Commercial Operation
Date, a standby letter of credit confirmed by a local bank in favor of
NPC (the "Construction Performance Bond") in the agreed form and in an
amount equal to sixty (60) US$ multiplied by the Contracted Capacity
(expressed in Kilowatts) (US$18,240,000.00) without need of demand
from NPC.
21
<PAGE>
The form of the Construction Performance Bond is attached hereto as
the Eighteenth Schedule.
(c) To secure NPC against an Abandonment by SPCC of the Cogeneration Power
Production Facility during the period from the Commercial Operation
Date up to the end of the Cooperation Period and to secure the due
payment of amounts due to NPC by SPCC under this Agreement, SPCC shall
cause to be issued and delivered to NPC immediately before the
Commercial Operation Date, and maintained in full force and effect
during each year falling within such period, a standby letter of
credit confirmed by a local bank in favor of NPC (the "O & M Bond") in
the agreed form and in an amount equal to thirty (30) US$ multiplied
by the Contracted Capacity (expressed in Kilowatts) (US$9,120,000.00).
The form of the O & M Bond is attached hereto as the Nineteenth
Schedule. To the extent NPC makes demand and is paid under the O&M
Bond for payment defaults by SPCC under this Agreement, SPCC shall
cause the O&M Bond to be reinstated for its full value at all times.
(d) For purposes of this Agreement, the Cogeneration Power Production
Facility shall be deemed to have been Abandoned, and an Abandonment
shall have occurred, if:
(i) SPCC notifies NPC in writing that it has decided to terminate
all construction work or operations of the Cogeneration Power
Production Facility other than by reason of Force Majeure or
fault of NPC and does not intend to recommence such work; or
(ii) SPCC fails to resume construction or operation of the
Cogeneration Power Production Facility within one hundred
eighty (180) Days of termination or cessation of any event of
Force Majeure (or delay occasioned by an event of Force
Majeure) other than by reason of another event of Force
Majeure; or
(iii) SPCC fails to achieve Site/Project Mobilization by the Target
Commercial Operation Date due to the fault of SPCC and through
no fault of NPC; or
(iv) the Commercial Operation Date shall have failed to occur within
nine (9) months after the Target Commercial Operation Date due
to the fault of SPCC and through no fault of NPC; or
(v) the shareholders of SPCC shall have passed a resolution for the
winding-up of SPCC, or SPCC shall have commenced proceedings
before any court or administrative tribunal for winding-up,
dissolution, bankruptcy, insolvency, or similar relief, or
become subject to a final order or decree in any such
proceeding; or
(vi) due to the fault of SPCC, there shall have been a transfer or
conveyance of SPCC's right to own and/or operate the
Cogeneration Power Production Facility to any person without
the prior written approval of NPC, except as specifically
permitted pursuant to this Agreement; or
22
<PAGE>
(vii) following the Commercial Operation Date, the Cogeneration Power
Production Facility shall not have generated energy for a
period exceeding 180 consecutive Days, due to the fault of SPCC
and through no fault of NPC.
(e) SPCC shall cause the Development Bond, the Construction Performance
Bond and the O&M Bond to be maintained in force and effect in the
applicable amounts set forth above until the Site/Project Mobilization
Date, Commercial Operation Date and the end of the Cooperation Period,
respectively. For such purpose, SPCC shall ensure that, on a timely
basis, the Development Bond (if expiring by its terms before the
Site/Project Mobilization Date), the Construction Performance Bond (if
expiring by its terms before the Commercial Operation Date) and the
O&M Bond (if expiring by its terms before the end of the Cooperation
Period) are extended, renewed or replaced at least fifteen (15) Days
before their respective expiry dates, in each case for a term not
shorter than six (6) calendar months.
ARTICLE 4 - TESTING
4.1 TESTING PROCEDURES.
------------------
4.1.1 Without prejudice to Article 4.1.2, after the Site/Project
Mobilization Date, SPCC shall provide to NPC a list of Tests and
equipment inspections of the Cogeneration Power Production Facility
(or every part thereof) which are to be carried out, whether before
or after the Commercial Operation Date, and of the place and the
scheduled time at which any such Test or inspection is to be
conducted, and shall keep NPC fully informed of any material changes
thereto. NPC shall notify SPCC in writing which Tests will be
witnessed by NPC.
4.1.2 Not later than six (6) months and not earlier than nine (9) months
prior to the then scheduled start of the Guarantee Tests, SPCC shall
notify NPC in writing of its proposed (and, as soon as practicable
thereafter the Parties shall meet to agree on) procedures,
standards, protective settings, duration and program consistent with
the Fourteenth Schedule (Tests and Test Procedure) for:
(a) the Guarantee Test and all other Tests of the Cogeneration
Power Production Facility mentioned in the Fourteenth Schedule
to be conducted before the Commercial Operation Date; and
(b) the Performance Tests and all other Tests of the Cogeneration
Power Production Facility mentioned in the Fourteenth Schedule
to be conducted during the Cooperation Period.
To the extent the Parties are unable to agree, the matter shall be referred
to an Expert for resolution.
23
<PAGE>
4.2 WITNESSING OF TESTS.
-------------------
4.2.1 NPC shall have the right to witness all Tests of the Cogeneration
Power Production Facility or any part thereof, and SPCC shall
procure any necessary consent of its contractors and suppliers
thereto.
4.2.2 SPCC shall give NPC fourteen (14) Days written notice of any Tests
mentioned in Article 4.1.1 which are to be conducted on the Site (or
within the Philippines) and sixty Days written notice of any such
Tests which are to be conducted outside of the Philippines.
4.2.3 Provided notice has been given pursuant to this Article 4, Tests may
be conducted validly at the notified times in the absence of
representatives of NPC. If SPCC fails to give proper notice under
this Article 4, the Test concerned, if conducted in the absence of
NPC unless NPC otherwise agrees, shall be invalid and shall be
repeated (subject again to the notice requirements of this Article
4) at the cost, risk and expense of SPCC.
4.2.4 No Guarantee Test or Performance Test shall be regarded as
successfully completed until the result thereof has been jointly
certified by SPCC and NPC in accordance with Article 4.6. To the
extent the Parties are unable to agree, the matter shall be referred
to an Expert for resolution.
4.2.5 SPCC shall coordinate with NPC's Systems Operations Department to
establish the actual testing dates.
4.3 GUARANTEE TEST.
---------------
4.3.1 The Guarantee Test shall demonstrate to NPC that the Cogeneration
Power Production Facility is capable of operating on a continuous
and reliable basis in accordance with the Operating Parameters and
the Specifications for a period of seven days and shall be used to
prove the Contracted Capacity as of the Commercial Operation Date.
4.3.2 In the event that the Guarantee Tests demonstrate that the
Cogeneration Power Production Facility is capable of operating on a
continuous and reliable basis in accordance with the Operating
Parameters and the Specifications, SPCC and NPC shall jointly
certify that the Guarantee Tests were successfully completed. The
Commercial Operation Date shall occur on the Target Commercial
Operation Date or the date the Guarantee Tests are successfully
completed, whichever is later. The Net Available Capacity shall be
based on the actual results of the Guarantee Test, but shall in no
event be greater than 304,000 kW.
4.3.3 If the Guarantee Tests have demonstrated that the Net Available
Capacity is less than the Contracted Capacity, SPCC may elect (by
notice to NPC within fifteen Days after completion of the Guarantee
Test) that the Commercial Operation Date be deemed to have occurred.
SPCC shall have no liability to NPC in respect of the reduced
capacity beyond the effects thereof on the calculation of the
Capital Recovery Fees and the Fixed O & M Fees to be paid by NPC
under the Eighth Schedule. SPCC may retest at any time, upon giving
notice as required in Article 4.2, if the capacity demonstrated in
the Guarantee Tests is lower than 304,000 kW.
24
<PAGE>
4.3.4. The Guarantee Tests will be performed in accordance with the
provisions of this Article 4 and of the Fourteenth Schedule (Test
and Test Procedures).
4.4 PERFORMANCE TEST.
-----------------
4.4.1 The Performance Test shall prove the Net Available Capacity
nominated by SPCC for the Contract Year.
4.4.2 The Performance Test shall be done within fifteen (15) Days after
each anniversary of the Commercial Operation Date, or such other
date as the Parties may mutually agree, and in accordance with the
provisions of this Article 4 and the Eighth Schedule and the
Fourteenth Schedule (Test and Test Procedures). SPCC may retest up
to three times within the fifteen Day period described above;
provided, however, that NPC shall be given twenty-four (24) hours'
telephonic or written notice of each retest. Additional retests may
be carried out with NPC's reasonable approval. The results of the
most recent Performance Test (including any retesting carried out
pursuant to this Article 4.4.2) shall be effective for the purpose
of determining deliveries and payments commencing at the start of
the next Contract Year.
4.4.3 If, for any reason, SPCC is unable to conduct a Performance Test at
the time scheduled for such Performance Test, SPCC shall promptly
reschedule the Performance Test and shall give NPC at least twenty-
four (24) hours' written notice of the rescheduled Test date. If
SPCC shall have failed to conduct a Performance Test within the
fifteen Day period described in Article 4.4.2, then the Performance
Test shall be deemed to have demonstrated that the Cogeneration
Power Production Facility is not Available. The foregoing shall not
apply if SPCC's failure to conduct the Performance Test is due to an
event of Force Majeure (including any failure of NPC to take
electricity).
4.4.4 Yearly nomination of the Net Available Capacity for the following
Contract Year shall be made by SPCC to NPC not later than thirty
(30) Days prior to the anniversary of the Commercial Operation Date.
4.4.5 If SPCC fails to provide its nomination to NPC as provided above,
the Net Available Capacity shall be equal to the Net Available
Capacity in effect during the previous Contract Year until such time
that SPCC shall have nominated and performed the required Tests in
accordance with this Article 4 and the Fourteenth Schedule. SPCC
shall (if required by NPC) and may (with the reasonable approval of
NPC and upon forty-eight (48) hours' telephonic or written notice to
NPC) carry out a Performance Test of the Cogeneration Power
Production Facility at any time to determine Net Available Capacity.
However, no more than four Performance Tests may be carried out in
any Contract Year, except for retests permitted under Article 4.4.2
and tests required by NPC, neither of which shall count toward this
limit. If the results of such Performance Test requested by NPC show
that the Net Available Capacity is lower than the previous Contract
Year's Net Available Capacity, SPCC shall refund to NPC excess
payments for the Capital Recovery Fees and the Fixed O & M Fees
during
25
<PAGE>
the current Contract Year that the previous Contract Year's Net
Available Capacity was in effect.
To the extent the Parties are unable to agree, the matter shall be referred
to an Expert for resolution.
4.5 COST OF TESTING AND PURCHASE OF ELECTRICITY.
--------------------------------------------
During testing and commissioning of the Cogeneration Power Production
Facility prior to the Commercial Operation Date:
(a) SPCC shall at its own cost supply Fuel and
(b) NPC shall take all electricity generated by the Cogeneration Power
Production Facility during Tests and supplied at the Delivery Point,
and shall pay Energy Fees therefor at fifty percent of the base energy
rate set forth in the Eighth Schedule.
If after completion of such testing but prior to the Commercial Operation
Date, NPC desires to purchase energy from the Cogeneration Power Production
Facility, then the Parties shall agree in writing upon the terms and
conditions of such purchase.
4.6 CERTIFICATION.
--------------
4.6.1 Forthwith, upon the completion of the Guarantee Tests or Performance
Tests pursuant to this Article 4 and the Fourteenth Schedule, SPCC
and NPC shall jointly certify the result of such Tests. NPC shall
not unreasonably withhold its certification.
4.6.2 Any other material Tests of the Cogeneration Power Production
Facility (and the constituent parts thereof) to be completed before
the Commercial Operation Date successfully completed shall be
certified by SPCC in writing and SPCC shall provide NPC with a copy
of such a certificate.
4.6.3 To the extent the Parties cannot agree upon whether or not a Test
has been successfully completed, the matter shall be referred to an
Expert for resolution. The Expert shall be directed to award
interest at the Agreed Interest Rate on amounts not paid when due.
The Expert shall have the power to award penalties in the event that
the Expert determines that a Party has unreasonably withheld its
certification, in an amount not to exceed three times the actual
damages incurred by the other Party (including, in addition to
amounts not paid when due, all liabilities, damages, and all
reasonable costs payable to any third parties as a result of such
delay, plus interest at the Agreed Interest Rate thereon from the
date incurred).
4.7 DEEMED COMPLETION.
------------------
4.7.1 If the Commercial Operation Date has not occurred only because the
Guarantee Tests cannot successfully be carried out because NPC
cannot take the electricity which will be generated during such
Tests because the Transmission Line is not complete, the Commercial
Operation Date shall
26
<PAGE>
be deemed for all purposes of this Agreement to occur on the date on
which it would otherwise have occurred, as notified in writing by
SPCC to NPC ("Deemed Completion Date") but not, for the avoidance of
doubt, before what would have been the Target Commercial Operation
Date, but for such failure. On and from such date, the Cogeneration
Power Production Facility shall be deemed to be Available, with a
Net Available Capacity equal to 304,000 kW, and NPC shall pay
Availability Fees based upon such capacity until the Net Available
Capacity is established pursuant to the Guarantee Test.
4.7.2 In the circumstances mentioned in Article 4.7.1 above, NPC shall
notify SPCC at least thirty (30) Days prior to the Transmission Line
Completion Date, and SPCC shall initiate start-up, commissioning and
testing activities no later than fifteen (15) Days after the
Transmission Line Completion Date. SPCC shall schedule the Guarantee
Test for as soon as reasonably possible after NPC notifies SPCC in
writing that it is able to take the electricity generated by the
Cogeneration Power Production Facility. If, for any reason, SPCC is
unable to conduct the Guarantee Test at the time scheduled for such
Test, SPCC shall promptly reschedule the Test and shall give NPC at
least five (5) Days written notice of the rescheduled Test date. If
SPCC shall have failed to conduct the Guarantee Test within one
hundred twenty (120) Days of the Transmission Line Completion Date,
then the Guarantee Test shall be deemed to have demonstrated that
the Cogeneration Power Production Facility is not Available. The
foregoing shall not apply if SPCC's failure to conduct the Guarantee
Test is due to an event of Force Majeure (including any failure of
NPC to take electricity or any failure of NPC to give proper,
accurate notice of the Transmission Line Completion Date).
4.7.3 If NPC has made payments to SPCC of Availability Fees based upon a
Net Available Capacity of 304,000 kW pursuant to Article 4.7.1
above, and if upon completion of the Guarantee Test (and any
retesting carried out pursuant to this Agreement) the Net Available
Capacity is determined to be less than 304,000 kW or the
Cogeneration Power Production Facility is deemed not Available
pursuant to Article 4.7.2, then the fees previously paid by NPC
pursuant to Article 4.7.1 shall be recalculated based on the actual
Net Available Capacity, and SPCC shall reimburse NPC for the
overpayments (in the currencies in which such payments were made by
NPC), plus interest thereon at the Agreed Interest Rate.
4.7.4 To the extent the Parties cannot agree upon whether or not SPCC
shall have achieved the Deemed Completion Date, the matter shall be
referred to an Expert for determination.
ARTICLE 5 - OPERATION OF THE COGENERATION
POWER PRODUCTION FACILITY
5.1 SPCC'S RESPONSIBILITIES. SPCC shall be responsible, at its own cost, for
------------------------
the management, operation, maintenance and repair of the Cogeneration Power
Production Facility and Switchyard Facilities during the Cooperation Period
and shall use its reasonable efforts to ensure that during such period the
Cogeneration Power Production Facility is in good operating condition and
capable of
27
<PAGE>
generating electricity in a safe and reliable manner within the Operating
Parameters. Except in an Emergency (when it shall use all reasonable
endeavors to comply with dispatch instructions), SPCC shall not be obliged
to operate the Cogeneration Power Production Facility other than within the
Availability and actual Operating Parameters last advised by it to NPC
pursuant to Article 5.3.
5.2 DOWNTIME. Notwithstanding Article 5.1, SPCC shall be entitled to periods
---------
of Planned Maintenance and Forced Outage (as defined in the Sixth Schedule)
in order to undertake necessary overhaul, maintenance, inspection, repair
and turbine washing subject to the provisions of the Sixth Schedule, and
shall not be obliged to operate the Cogeneration Power Production Facility
inconsistently therewith.
5.3 AVAILABILITY.
-------------
5.3.1 SPCC shall at all times keep NPC advised of the current and
anticipated Availability and actual Operating Parameters of the
Cogeneration Power Production Facility. Without prejudice thereto,
SPCC shall comply with the Sixth Schedule.
5.3.2 SPCC shall not advise of nor permit to remain outstanding any advice
as to Availability and Operating Parameters containing levels
different from those which the Cogeneration Power Production
Facility is capable of achieving. This shall not oblige SPCC to
advise NPC of levels in excess of those specified in the First and
Second Schedules.
5.3.3 To the extent that an event of Force Majeure (other than Government
Force Majeure) affects NPC's ability to take electricity from the
Cogeneration Power Production Facility, but the Cogeneration Power
Production Facility would have been able to deliver electricity in
accordance with the terms and conditions of this Agreement, the
Cogeneration Power Production Facility shall be deemed not Available
(and the term "Force Majeure Outage" as used in the Eighth Schedule
shall include all such reductions in Availability) to the extent it
cannot be operated because of NPC's failure to take electricity
because of Force Majeure (other than Government Force Majeure); but
only for a period equal to the duration of the actual event or
circumstance of Force Majeure and for a maximum of seven additional
days, in the aggregate, in any Contract Year. The time taken to
overcome an event or occurrence of Force Majeure, as well as the
time during which the effects of Force Majeure subsist, shall not,
for the purposes of the foregoing, be considered in determining the
duration of the actual event or occurrence of Force Majeure.
5.4 OPERATION.
----------
5.4.1 The Cogeneration Power Production Facility shall be operated as a
base load generating unit at a nearly continuous level of output,
except during periods of Downtime and Forced Outages as more
specifically described in the Sixth Schedule (Electricity Delivery
Procedures), subject to this Agreement, and safe operating practices
pursuant to the Second Schedule (Operating Parameters) and Good
Operating Procedures.
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<PAGE>
5.4.2 SPCC shall only operate the Cogeneration Power Production Facility
in accordance with the dispatch instructions given in accordance
with the Sixth Schedule. However, and without prejudice to the Sixth
Schedule, SPCC shall not be obliged to operate the Cogeneration
Power Production Facility other than within the Availability and
actual Operating Parameters last advised by it pursuant and subject
to Article 5.3.1 and 5.3.2 (except in an Emergency, when SPCC shall
use all reasonable efforts to comply).
5.5 SPCC'S RIGHTS. Pursuant to its obligations under Article 5.1 of this
--------------
Agreement, SPCC shall have all the rights of an owner and operator of a
Cogeneration Power Production Facility, including among other things the
right to:
5.5.1 enter into contracts for the supply of materials and services, for
operation and maintenance, and for the sale of steam to the Thermal
Hosts;
5.5.2 appoint and remove consultants and professional advisers;
5.5.3 purchase replacement equipment;
5.5.4 appoint, organize and direct staff and manage, and supervise the
Cogeneration Power Production Facility;
5.5.5 establish and maintain regular inspection, maintenance and overhaul
procedures; and
5.5.6 do all other things necessary or desirable for the operation of the
Cogeneration Power Production Facility within the Operating
Parameters set forth in the Second Schedule.
5.6 NPC'S OBLIGATIONS. NPC shall:
------------------
5.6.1 endeavor to ensure that there is a supply of electricity as provided
in Article 2 and the First Schedule (Project Scope and
Specifications), the cost of the utilization of which shall be for
SPCC's account; and
5.6.2 at its own cost, construct, install, maintain and repair the
Transmission Line and ensure that at all times the Transmission Line
is capable of operating within the specifications set out in the
Fifth Schedule (Transmission Line Specifications).
5.7 ENVIRONMENTAL IMPACT. SPCC shall monitor and produce reports (copies of
---------------------
such reports to be furnished to NPC) on the environmental impact of the
Cogeneration Power Production Facility in accordance with the requirements
of the Environmental Compliance Certificate, and shall operate the
Cogeneration Power Production Facility in compliance with the requirements
of the Environmental Compliance Certificate and the Sixteenth Schedule
(Environmental Criteria).
5.8 SAFETY AND TECHNICAL GUIDELINES/ GRID CODE.
-------------------------------------------
5.8.1 NPC and SPCC shall organize a Steering Committee which shall, from
time to time, coordinate, meet, discuss and agree upon safety and
technical guidelines for the operation of the Cogeneration Power
Production Facility
29
<PAGE>
in accordance with the Operating Parameters, the Specifications,
NPC's System requirements and the Grid Code. The Steering Committee
shall also serve as a venue for the discussion of contractual issues
and concerns in relation to the Cogeneration Power Production
Facility. The Committee shall be composed of six members. three to
be nominated by SPCC and three to be nominated by the Regional
Center, one of which should be from Systems Operations (Luzon).
5.8.2 The Parties acknowledge that no Grid Code has yet been adopted in
the Philippines. To the extent that the Grid Code, if and when
adopted, imposes monetary burdens on the Project (such as
requirements for the installation of equipment not contemplated in
the First Schedule), SPCC shall give NPC notice of the costs of
complying therewith, and NPC shall reimburse SPCC for such costs.
NPC or the appropriate governmental authority shall have the right
to audit all costs to NPC by SPCC.
ARTICLE 6 - SALE OF ELECTRICITY
PART A: SUPPLY OF ELECTRICITY
6.1 SUPPLY TO NPC. SPCC agrees to sell electricity to NPC and NPC agrees to
--------------
take and pay for all electricity delivered to NPC in accordance with the
procedures set out in the Sixth Schedule (Electricity Delivery Procedures)
and the Operating Parameters set out in the Second Schedule (Operating
Parameters).
6.2 QUANTITY. The quantities of electricity delivered to NPC by SPCC at the
---------
Delivery Point from time to time shall be monitored, measured and recorded
in accordance with the provisions of the Seventh Schedule (Measurement and
Recording of Electricity).
6.3 DELIVERY. SPCC shall deliver the entire Cogeneration Power Production
---------
Facility power output (net of Cogeneration Power Production Facility usage
and subject to Article 2.9.4) to NPC at the Delivery Point on the outgoing
line consistent with the Seventh Schedule (Measurement and Recording of
Electricity). It is acknowledged that (except as otherwise provided in the
Sixth Schedule) the Cogeneration Power Production Facility shall operate as
base load plant; provided, however, that SPCC shall comply with the terms
and conditions of the Sixth Schedule in accommodating dispatch orders
validly given in accordance therewith.
PART B: FEES
6.4 FEES.
----
6.4.1 During the Cooperation Period NPC shall pay SPCC Availability Fees
and Energy Fees, in each case calculated as provided in the Eighth
Schedule.
6.4.2 Fuel Fees shall be payable from and after the Commercial Operation
Date calculated on the basis of all kWhs delivered to the Delivery
Point on the outgoing line at the heat rate guaranteed in the Eighth
Schedule.
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<PAGE>
6.4.3 In the event of an occurrence of Force Majeure described in Article
13.1 (a) (except Force Majeure related solely to the Thermal Hosts)
which renders the Cogeneration Power Production Facility unable to
operate, or an occurrence of Force Majeure which renders NPC unable
to take electricity and results in the Cogeneration Power Production
Facility being deemed not Available during the occurrence of the
Force Majeure event pursuant to Article 5.3.3, either of which
results in a reduction of Availability Fees pursuant to the Eighth
Schedule, the Cooperation Period shall be extended to account for
the number of kWh lost due to the event of Force Majeure.
6.5 INVOICES. In respect of each Billing Period, SPCC will deliver to NPC an
---------
invoice (in US$ and/or Philippine Pesos as required by the Eighth Schedule)
in respect of Capital Recovery Fees, Fixed Operating and Maintenance
Fees, Energy Fees and Fuel Fees for such Billing Period and NPC shall pay
to SPCC the amount of such invoice within thirty (30) Days after the
receipt of such invoice.
6.6 PAYMENT BY NPC. All fees payable to SPCC pursuant to this Article 6 shall
---------------
be paid in the currencies stipulated in the Eighth Schedule (Delivery of
Power and Energy) and each sum payable shall be decreased or increased so
as to ensure that after NPC has deducted therefrom all taxes or charges for
which NPC is liable for pursuant to Article 10.1, if any, (which taxes and
charges shall be separately stated in all invoices and are to be paid in
Pesos), there remains a sum equal to the amount that would have been
payable to SPCC had there been no requirement to deduct or withhold such
taxes or other charges.
6.7 NO SET-OFF. Except as set forth above or as required by the Law of the
-----------
Republic of the Philippines, all payments made by NPC hereunder shall be
made free and clear of and without deduction for or on account of any set-
off, counterclaim, tax or otherwise except for taxes payable by SPCC which
are required by Law to be withheld by NPC and except as specifically
permitted pursuant to Article 6.10.
6.8 DISPUTES. If NPC disputes the amount specified in any invoice it shall so
---------
inform SPCC within fifteen (15) Days of receipt of such invoice. If the
dispute is not resolved by the invoice due date, NPC shall pay the
undisputed amount on or before such date. The disputed amount shall be
resolved according to Article 19 within fifteen (15) Days after the invoice
due date for such invoice (for a total of forty-five (45) Days after
receipt of such invoice) and all or any part of the disputed amount which
is finally determined pursuant to Article 19 or Article 23 to be payable to
SPCC shall be paid together with interest pursuant to Article 29.1 from the
due date of payment until payment in full.
PART C: FOREIGN EXCHANGE
6.9 DOLLAR PAYMENTS. All sums payable to SPCC in dollars shall be payable in
----------------
dollars in New York, in same-day funds, on the day when payment is due, to
the account of SPCC at ______(Bank)_______or such other account as SPCC may
specify and is acceptable to NPC which acceptance shall not be unreasonably
withheld.
6.10 COST OF PAYMENTS. Any costs incurred by NPC in connection with the
-----------------
remittance of funds outside the Philippines shall be for SPCC's account and
shall
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<PAGE>
be deducted from the amount so remitted, provided that the portion of
any regular and generally applicable bank charges, fees, and Documentary
Stamp Tax in excess of 0.15% of the amount remitted shall be for the
account of NPC and shall be paid by NPC directly to the remitting bank.
6.11 PESO PAYMENTS. All sums payable to SPCC in Pesos shall be payable in Pesos
--------------
in Manila, in same-day funds, on the day when payment is due, to the
account of SPCC with a bank in Manila that SPCC shall specify and is
acceptable to NPC which acceptance shall not be unreasonably withheld.
6.12 PAYMENTS TO NPC. All sums payable by SPCC to NPC, whether pursuant to
----------------
judgment or otherwise, shall be payable in same-day funds, on the day when
payment is due, to the account of NPC with a bank in Manila that NPC shall
specify.
6.13 DOLLAR DEFICIENCY. In the event that any payment, whether pursuant to
------------------
judgment or otherwise, upon prompt conversion to dollars and transfer to
New York, as provided in Article 6.9, does not result in payment of the
dollar amount stipulated in this Agreement, SPCC shall be entitled to
immediate payment of, and shall have a separate cause of action for, the
dollar deficiency plus interest thereon pursuant to Article 29. However,
should any such payment (upon conversion to dollars and transfer to New
York as aforesaid) result in the receipt by SPCC of a sum in excess of the
dollar amount stipulated in this Agreement, SPCC shall notify and pay the
excess amount to NPC immediately upon SPCC's receipt of notice of the over-
payment and its agreement to the same plus interest thereon pursuant to
Article 29.
PART D: CHANGE IN CIRCUMSTANCES
6.14 CHANGE IN CIRCUMSTANCES.
------------------------
6.14.1 If, as a result of any Law coming into effect after the Contract
Signing Date, or any Law (including any Law or any official written
interpretation thereof, which SPCC has relied upon in entering into
this Agreement, but excluding such Laws that only affect any Thermal
Host in its capacity as thermal host and purchaser of steam) in
force at the date hereof being amended, modified or repealed, or as
a result of any Consent in effect as of the Contract Signing Date
being subsequently terminated, withdrawn, rescinded or amended or as
a result of any new required Consent not being obtained on a timely
basis for reasons other than fault of SPCC, the Cogeneration Power
Production Facility is unable to operate in accordance with the
Specifications or within the Operating Parameters, and/or the
interest of SPCC in the Site, the Project or the Facilities and/or
SPCC's economic return on its investment (net of Philippine taxes
and other impositions) is materially reduced, prejudiced or
otherwise adversely affected (including without limitation, any
restriction on the ability to remit funds in dollars outside of the
Philippines), SPCC shall give NPC notice thereof with reasonably
full particulars of the Law concerned and of its proposal for and
the cost of complying therewith (which proposal should substantially
preserve SPCC's economic return at the least cost to NPC, consistent
with both Parties' obligations under this Agreement) and the Parties
shall promptly meet and seek, in good faith (including by the
provision of information and data), to agree on amendments to this
32
<PAGE>
Agreement which will substantially preserve SPCC's said economic
return at the least cost to NPC consistent with both Parties'
obligations under this Agreement. If the Parties are unable to come
to an agreement on appropriate amendments, the issue of how to amend
this Agreement within the stated parameters shall be resolved
according to Article 19 and, failing resolution thereunder, shall be
referred to arbitration pursuant to Article 23.
6.14.2 If the circumstances mentioned above materially and favorably affect
(or, in the reasonable opinion of NPC notified to SPCC, may
materially and favorably affect) the said economic return of SPCC,
SPCC shall give NPC notice thereof with reasonably full particulars
of the Law concerned and of its proposal for and the savings
resulting from taking advantage thereof (which proposal should
maintain SPCC's economic return at the greatest savings for NPC
consistent with both Parties' obligations under this Agreement) and
the Parties promptly shall meet and seek, in good faith (including
by the provision of information and data), to agree on amendments to
this Agreement which will maintain SPCC's economic return at the
greatest savings to NPC consistent with both Parties' obligations
under this Agreement. If the Parties are unable to come to an
agreement on appropriate amendments, the issue of how to amend this
Agreement within the stated parameters shall be resolved according
to Article 19 and, failing resolution thereunder, shall be referred
to arbitration pursuant to Article 23.
6.14.3 For the purpose of determining whether a change in circumstances has
occurred, a Consent obtained after the Contract Signing Date shall
not be considered a change in circumstances unless such Consent was
given on terms which are materially different from those which SPCC
(to the best of its knowledge) could reasonably have expected
immediately prior to the Contract Signing Date.
6.15 CONVERSION TO OTHER FUEL.
-------------------------
6.15.1 Conversion to Other Fuels. If and when Fuel is either unavailable
-------------------------
or the Parties agree that there is another fuel which: (1) meets or
betters the environmental criteria set forth in the Sixteen Schedule
(Environmental Criteria); (2) satisfies the turbine warranties and
specifications; and (3) is more economical on an overall basis for
the Parties and the Project (taking into account fuel price and
operation and maintenance considerations), the Parties may agree to
an alternate fuel. The Thermal Efficiency Standards under such
conditions shall remain pegged at 60%, computed on an annual basis.
The Parties shall revise the Fourth Schedule (Fuel and Fuel Testing)
to specify the cost basis of the alternate fuel.
6.15.2 Conversion to Natural Gas. If and when natural gas becomes
--------------------------
available for use at the Cogeneration Power Production Facility, NPC
may request SPCC to convert the Cogeneration Power Production
Facility to operate on natural gas subject to an agreement on
revised fees (pursuant to the Eighth Schedule) and parameters. If
the Parties mutually agree to a change of fuel pursuant to this
Article 6.15.2, then:
33
<PAGE>
6.15.2.1 if the result is an increase in output due solely to the
change in fuel, the Parties shall revise the Capital
Recovery Fees and the Fixed Operating and Maintenance Fees
so that SPCC is revenue neutral;
6.15.2.2 the Parties shall endeavor to make any adjustments in the
Base Energy Rate necessary or appropriate to adequately
compensate SPCC for the change in operating parameters
attributable to the change in fuel;
6.15.2.3 the Parties shall revise the Fuel Fee equation applicable
to the use of natural gas; and
6.15.2.4 the Thermal Efficiency Standards for natural gas shall be
57% pursuant to DOE Circular No. 96-01-005.
ARTICLE 7 - TERM AND TERMINATION
7.1 TERM. The term of this Agreement shall begin from the Contract Signing
-----
Date hereof and shall end on the last day of the Cooperation Period of
twenty five (25) Years from the Commercial Operation Date unless otherwise
provided herein or subsequently earlier terminated as agreed to by the
Parties.
7.2 TERMINATION BY NPC. NPC shall have the right to terminate this Agreement
-------------------
upon 30 Days' written notice to SPCC:
(a) if SPCC Abandons the Cogeneration Power Production Facility;
(b) if SPCC fails to deliver and maintain any Bond as and when required by
this Agreement within fifteen (15) Days of a request therefor by NPC;
and
(c) if SPCC fails to obtain and maintain any insurance as required by this
Agreement or fails within fifteen (15) Days of a request therefor by
NPC to provide NPC with evidence reasonably satisfactory to it that
any insurance required by this Agreement is maintained.
7.3 TERMINATION BY SPCC.
--------------------
(a) SPCC shall have the right to terminate this Agreement upon 30 Days'
written notice to NPC if NPC by reason of its insolvency or otherwise
has failed to pay or ensure the due payment of any sum due under this
Agreement (as the same may have been amended by mutual agreement or by
arbitration pursuant to Article 23) within ninety (90) Days of the due
date of such payment.
(b) SPCC shall have the right to terminate this Agreement upon 30 Days'
written notice to NPC if periods of Government Force Majeure have
resulted in the Target Commercial Operation Date being extended by
twelve months.
7.4 EXERCISE OF TERMINATION PAYMENT BY NPC. NPC shall have the right to
---------------------------------------
terminate this Agreement if any period of Government Force Majeure during
the Cooperation Period continues for more than twelve calendar months.
34
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7.5 PRE-COMPLETION TERMINATION AND PAYMENT.
---------------------------------------
7.5.1 If this Agreement is terminated prior to the Commercial Operation
Date pursuant to Article 7.3 or 7.4:
(a) NPC shall not be entitled to draw upon the Development Bond or
the Construction Performance Bond (and NPC shall promptly
return such Bond to SPCC);
(b) NPC shall pay SPCC a termination charge (calculated and paid in
U.S. Dollars) equal to the aggregate of all costs, expenses and
liabilities, including but not limited to all principal,
interest and fees owed by SPCC to its Lenders, any other
interest and any fees incurred by SPCC in connection herewith,
plus an amount sufficient to provide SPCC with a return on
equity of twelve (12%) percent per annum on the equity invested
in the Project, for the period when the equity was invested;
and
(c) the termination shall be effective thirty (30) Days after the
termination notice is given, at which time NPC shall pay SPCC
the applicable termination charges and SPCC shall transfer the
Generating Assets (other than the Site) to NPC on an "as is"
basis.
7.5.2 If this Agreement is terminated prior to the Commercial Operation
Date pursuant to Article 7.2 (a), (b) or (c), NPC shall be entitled
to draw the remaining amount of the then applicable Bond at the time
of termination.
7.6 POST-FACILITY COMPLETION TERMINATION AND PAYMENT.
------------------------------------------------
7.6.1 If this Agreement is terminated on or after the Commercial Operation
Date pursuant to Article 7.3 or 7.4:
(a) NPC shall not be entitled to draw upon the Construction
Performance Bond or the O&M Bond (and NPC shall promptly return
such Bond to SPCC);
(b) NPC shall pay SPCC the applicable termination charges
determined in accordance with the Twentieth Schedule
(Termination Price); and
(c) The termination shall be effective thirty (30) Days after the
termination notice is given, at which time NPC shall pay SPCC
the applicable termination charges. In the event that there is
no Viable Market (as defined in the Twentieth Schedule) as of
the effective date of the termination, SPCC shall transfer the
Generating Assets to NPC on an "as is" basis. In the event that
a Viable Market exists, SPCC shall retain ownership of the
Generating Assets.
7.6.2 If this Agreement is terminated on or after the Commercial Operation
Date pursuant to Article 7.2(a), (b) or (c), NPC shall be entitled
to draw the remaining amount of the O&M Bond at the time of
termination.
35
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7.7 DEDUCTIONS. In the event that the provisions of this Article apply as a
----------
result of an event of Force Majeure pursuant to Article 13, then there
shall be deducted from any sum payable by NPC to SPCC an amount equal to
the value, if any, of any applicable insurance proceeds received by SPCC,
in respect of the event leading to the operation of the provisions of
Article 13.
ARTICLE 8 - REPRESENTATIONS, WARRANTIES
AND COVENANTS OF SPCC
8.1 CORPORATE EXISTENCE.
--------------------
8.1.1 SPCC represents that it is a private corporation, duly organized and
existing under the laws of the Netherlands with the corporate power
and authority to execute, deliver and perform the terms and
conditions to be performed by it under this Agreement, and that as
of the date of this Agreement, the shareholders of SPCC are Texaco
Nederland, B.V., a wholly owned subsidiary of Texaco Inc., and MEC
San Pascual B.V., a wholly owned subsidiary of Edison Mission
Energy.
8.1.2 SPCC Philippines is, or when formed pursuant to Article 28 will be,
an entity duly organized and existing under the laws of the Republic
of the Philippines with the power and authority to execute, deliver
and perform the terms and conditions to be performed by it under the
Accession Undertaking. As of the date of the Accession Undertaking,
the partners in SPCC Philippines will be SPCC and Batangas Energy
Corporation, a wholly owned subsidiary of Caltex.
8.2 GOVERNMENT AUTHORIZATIONS. SPCC represents and warrants that it has taken
--------------------------
all necessary corporate action to enter into, execute, deliver and perform
this Agreement, and such will not constitute a breach of any agreement or
agreements to which it is a party; and prior to the Commercial Operation
Date as required in all Project Milestones, it will have secured or caused
to be secured all orders, consents, approvals, licenses and permits of all
relevant government or governmental agencies in order for it to construct,
own and operate the Cogeneration Power Production Facility.
8.3 COMPLIANCE WITH STANDARDS. SPCC warrants that the Cogeneration Power
--------------------------
Production Facility shall be constructed, operated and maintained in
accordance with Internationally Accepted Engineering Standards, Good
Operating Procedures and those internationally accepted environmental
standards which have been adopted by Law in the Philippines.
8.4 COMPLIANCE WITH LAWS. SPCC shall operate the Cogeneration Power Production
---------------------
Facility in accordance with all environmental and other Philippine and
local Laws in force as of the Contract Signing Date and shall comply with
any changes in such laws and regulations and with any new laws and
regulations, subject to Article 6.14.
8.5 SPCC'S WARRANTY AGAINST CORRUPTION. SPCC hereby warrants that neither it
-----------------------------------
nor its representatives have offered any government officer and/or NPC
official or employee any consideration or commission for this Agreement nor
has it or its representatives exerted or utilized any corrupt or unlawful
influence to
36
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secure or solicit this Agreement for any consideration or commission; that
SPCC shall not subcontract any portion or portions of the scope of the work
of the Agreement awarded to any person known by SPCC to be an official or
employee of NPC or to the relatives within the third degree of
consanguinity or affinity of the NPC officials who are directly or
indirectly involved in contract awards or project prosecution and that if
any commission is being paid to a private person, SPCC shall disclose the
name of the person and the amount being paid and that any material
violation of this warranty shall constitute a sufficient ground for the
rescission or cancellation of this Agreement or the deduction from the
contract price of the consideration or commission paid without prejudice to
the filing of civil or criminal action under the Anti-Graft law and other
applicable laws against SPCC and/or its representatives and NPC's officials
and employees.
ARTICLE 9 - REPRESENTATIONS, WARRANTIES
AND COVENANTS OF NPC
9.1 CORPORATE EXISTENCE. NPC represents that it is a corporation duly
--------------------
organized and existing under and by virtue of the laws of the Republic of
the Philippines, and has the corporate power and authority to execute,
deliver and carry out the terms and conditions of this Agreement.
9.2 GOVERNMENT AUTHORIZATIONS. NPC represents and warrants that it has taken
--------------------------
all necessary corporate action, and has secured or caused to be secured all
necessary government orders, consents or approvals, permits and licenses to
enter into, execute and perform this Agreement, to purchase power from
SPCC, and shall endeavor to secure all other governmental approvals and
registrations as may be required to enable it to make payments therefor in
the respective currencies referred to herein, and such will not constitute
a breach of any agreement or agreements to which it is a party.
ARTICLE 10 - TAXES
10.1 RESPONSIBILITY FOR TAXES.
-------------------------
10.1.1 In the performance of its obligations under this Agreement, SPCC
shall be responsible for:
(i) obtaining all permits, approvals, clearances relative to plant
construction and operation, including fees and other charges
thereof, required by various government agencies,
instrumentalities, subdivisions, entities, and/or private
institutions routinely needed and available for business
activities which any enterprise would be required to secure on
its own;
(ii) paying taxes imposed or calculated on the basis of the net
income of SPCC and personnel income taxes of its personnel,
and ensuring, on a best efforts basis, the payment of taxes
imposed on its contractors and sub-contractors;
(iii) paying taxes (such as input VAT) and duties on capital
equipment and spare parts in accordance with the policies,
guidelines, laws
37
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and regulations of the Philippines Board of Investment (BOI)
Investment Priorities Plan of 1996, and the Bureau of Internal
Revenue (BIR) or any taxing authority thereof;
(iv) paying local taxes, fees and charges imposed on SPCC;
(v) paying for the entitled benefits provided for in Energy
Regulations No. 1-94 "Benefit for LGUs, Regions, and Affected
Community and People Hosting Power Plants and Energy Resource
Development Projects" (as applicable);
(vi) paying all real estate taxes and assessments, rates and other
charges in respect of the Site, buildings and improvements on
the Site and the Cogeneration Power Production Facility;
In the event that a change in Law or any official written
interpretation thereof after the Contract Signing Date increases
SPCC's tax burden, the imposition of such additional taxes or
increase in tax burden shall be treated as a change in
circumstances, and Article 6.14 shall apply.
Nothing contained in this Agreement shall obligate NPC to be
responsible to any taxing authority for taxes imposed on SPCC's sub-
contractors. The Parties acknowledge that such taxes are the
responsibility of the subcontractors, and do not intend by this
Agreement to assume any responsibility to third parties with respect
to such taxes.
10.1.2 In light of NPC's exemption from VAT pursuant to Law, SPCC has
agreed not to charge VAT to NPC. SPCC desires to obtain a zero
rating from the Government of the Republic of the Philippines.
However, in the event that NPC or its successor or assign is
determined not to be exempt from VAT, SPCC shall have the right to
charge VAT to NPC or such successor or assign. Such VAT shall be
paid by NPC, or such successor or assign, in addition to the amounts
set forth in the Eighth Schedule. For the avoidance of doubt, no
Law, or change in Law, resulting in a determination that SPCC is
zero rated or a determination that NPC or its successor is not
exempt from VAT shall be considered a change in circumstances for
the purposes of Article 6.14.2.
10.2 PAYMENT RESPONSIBILITIES. NPC shall be responsible for reimbursing SPCC
-------------------------
for any fees that SPCC has paid, which fees are NPC's responsibility to
pay, within thirty (30) Days of written demand therefor. NPC or the
appropriate governmental authority shall have the right to audit all costs
charged to NPC by SPCC pursuant to this Article 10.2.
10.3 PAYMENTS FREE AND CLEAR. All sums payable by NPC under this Agreement
------------------------
whether by way of fees, reimbursement of expenses or taxes, or otherwise
shall be paid in full, without set-off or counterclaim, free of any
deductions or withholdings imposed by the Republic of the Philippines or
any agency or instrumentality thereof (including political subdivisions and
taxing authorities), all of which shall be for the account of NPC (except
those for which SPCC is to be responsible pursuant to Article 10.1). In the
event that NPC is prohibited by law from making payments hereunder free of
deductions or withholdings, then NPC shall pay such additional amounts to
SPCC as may be
38
<PAGE>
necessary in order that the actual amount received after deduction or
withholding (and after payment of any additional taxes or other charges due
as a consequence of the payment of such additional amounts) shall equal the
amount that would have been received if such deduction or withholding were
not required.
10.4 LATE PAYMENT
------------
10.4.1 BY NPC. If any amount payable by NPC to SPCC hereunder whether in
------
respect of fees or otherwise and whether pursuant to judgment or
otherwise is not received by SPCC on or before the due date NPC
shall pay interest thereon, calculated at the Agreed Interest Rate
from the date upon which it was due until the date which such amount
is received by SPCC.
10.4.2 BY SPCC. If any amount payable by SPCC to NPC, whether pursuant to
--------
judgment or otherwise, is not paid on or before the due date, SPCC
shall pay interest thereon, calculated at the Agreed Interest Rate
from the date that it was due until the date upon which such amount
is received by NPC.
ARTICLE 11- INSURANCE
11.1 INSURANCE. SPCC shall be responsible for obtaining insurance throughout
----------
the Cooperation Period as provided in the Tenth Schedule (Insurance) and
shall provide NPC with certificates of all insurance obtained with respect
to the Project. SPCC will obtain insurance from GSIS, to the extent such
insurance complies with the terms of this Agreement and is available on
commercially reasonable terms, and provided further that SPCC shall have
the right to arrange reinsurance. SPCC shall be entitled to endorse or
assign any insurance proceeds or claims hereunder in favor of any Lenders
providing financing for the Project. Unless NPC has failed to perform any
of its payment obligations hereunder and such failure is continuing, NPC
shall, subject to the rights of any Lender, have the right to cause the
proceeds of claims against such insurances, except third party liability
and workmen's compensation insurance, with respect to damage or other
casualty to the Cogeneration Power Production Facility, to be applied by
SPCC to repair or restore the Cogeneration Power Production Facility to its
previous condition.
11.2 ENDORSEMENTS. SPCC shall cause its insurers to provide endorsements naming
-------------
NPC and its employees as additional insureds under its comprehensive or
commercial general liability insurance policies relating to the ownership,
construction, operation and maintenance of the Cogeneration Power
Production Facility.
ARTICLE 12 - TRANSMISSION LINE
12.1 OWNERSHIP AND RESPONSIBILITIES. NPC shall construct the Transmission Line
-------------------------------
in accordance with the Fifth Schedule at its sole cost, risk and expense
and so that the Transmission Line Completion Date occurs not later than the
Target Transmission Line Completion Date. NPC shall maintain and operate
the Transmission Line thereafter until the end of the Cooperation Period.
39
<PAGE>
12.2 FAILURE TO TIMELY COMPLETE.
---------------------------
12.2.1 BY NPC OF THE TRANSMISSION LINE WHEN SPCC HAS ACHIEVED DEEMED
-------------------------------------------------------------
COMPLETION DATE. If, by the Target Commercial Operation Date, SPCC
---------------
has achieved the Deemed Completion Date, then NPC shall:
(a) pay Availability Fees as set forth in Article 4.7; and
(b) defend, indemnify and hold SPCC harmless against any and all
claims and demands for any liabilities (other than contractual
liabilities to the Thermal Hosts) and damages and all
reasonable costs payable to any third parties as a result of
such delay. The Parties shall consult with each other and take
all reasonable steps to minimize the losses of either Party
from the delay in completion of the Transmission Line and to
minimize any overall delay or prejudice to the Project. NPC or
the appropriate governmental authority shall have the right to
audit all costs charged to NPC by SPCC pursuant to this Article
12.2.1.
12.2.2 BY NPC OF THE TRANSMISSION LINE WHEN SPCC HAS NOT ACHIEVED THE
--------------------------------------------------------------
COMMERCIAL OPERATION DATE. If the Transmission Line is not
-------------------------
completed by the Target Transmission Line Completion Date and SPCC
has not achieved the Deemed Completion Date by the Target Commercial
Operation Date, then the Target Commercial Operation Date shall be
extended on a day for day basis, until either (a) SPCC achieves the
Deemed Completion Date, at which time if the Transmission Line is
still not capable of receiving power, the remedies provided for in
Article 12.2.1 shall apply calculated from the date on which the
Deemed Completion Date has occurred; or (b) the Transmission Line is
completed and is capable of receiving power, at which time NPC's
right to receive penalties shall commence after the Target
Commercial Operation Date as set forth in Article 12.2.3.
12.2.3 BY SPCC. If the Transmission Line is capable of receiving power and
-------
the Target Commercial Operation Date has occurred, but the
Cogeneration Power Production Facility is not Available, then SPCC
shall be subject to the penalties set forth in the Third Schedule.
12.3 TRANSFER OF OBLIGATION TO SPCC. Nothing contained in this Article shall
------------------------------
bar the Parties from entering into a separate agreement under which SPCC
would cause the Transmission Line to be built on or over rights of way or
easements obtained by NPC. NPC's obligation to obtain environmental
clearances, rights of way and easements in a timely fashion would remain
subject to Article 12.2.1.
ARTICLE 13 - FORCE MAJEURE
13.1 FORCE MAJEURE. A Party shall not be liable for any failure to perform an
--------------
obligation under this Agreement (including, in the case of NPC, to take
electricity) to the extent such performance is prevented, hindered or
delayed by:
40
<PAGE>
(a) events or circumstances (other than as mentioned in paragraph b.
below) which are beyond its reasonable control and the effects of
which cannot reasonably be overcome by it by the exercise of Good
Operating Procedures; or
(b)
i. war (whether declared or not), hostilities, belligerence,
blockade, revolution or insurrection occurring in (or initiated
by the Government of) the Republic of the Philippines;
ii. expropriation, requisition, confiscation, nationalization,
import restriction or closure of harbors, docks, canals or
other assistance to shipping or navigation by the government of
the Republic of the Philippines or any subdivision thereof;
iii. rationing or allocation, whether imposed by Law or by
compliance of industry at the insistence of the government of
the Republic of the Philippines or any subdivision thereof; or
iv. event, matter or thing which shall reasonably be within the
control of NPC or any Competent Authority, or any closure,
restriction or other material change in the operation of the
Refinery (to the extent not due to the negligence of the
Refinery or the Refinery's failure to comply with any Law in
effect as of the Contract Signing Date), which directly causes
a material and adverse impact on the Cogeneration Power
Production Facility, caused by or contributed by NPC or any
Competent Authority;
and, in any such case, the effects of which cannot reasonably be overcome
by it by the exercise of Good Operating Procedures.
The items set forth in Article 13.1(b), subsections (i) through (iv) above
shall be referred to as events of "Government Force Majeure", and each of
the foregoing events, matters or things described in this Article 13.1
shall be referred to as an event of "Force Majeure" in this Agreement;
provided that:
(c) Planned Maintenance;
(d) failure to pay money (except as a result of a total failure of the
worldwide money transfer system);
(e) Forced Outage, to the extent the result of actual or anticipated
mechanical or electrical derangement or component failure under design
operating conditions and when constructed, operated and maintained in
accordance with Good Operating Procedures;
(f) any failure by a Party to obtain and/or maintain and comply at all
times with the terms of all Consents necessary to enable it to fulfill
its obligations under this Agreement, if the reason for such failure
is the refusal by a Party concerned to accept conditions which are not
unduly onerous;
41
<PAGE>
(g) in the case of SPCC, any failure to obtain and maintain a bond or
insurance as required by this Agreement;
(h) in the case of SPCC, any event, matter or thing which shall reasonably
be within the control of SPCC;
(i) in the case of NPC, lack of market for electricity; and
(j) in the case of NPC, Government Force Majeure;
shall not be Force Majeure.
13.2 EXCEPTIONS.
-----------
13.2.1 Notwithstanding Article 13.1, NPC shall not be entitled to claim for
itself Force Majeure in respect of any event of Government Force
Majeure, and shall not be relieved of its obligation to make
payments of Availability Fees by the occurrence of such event of
Government Force Majeure, whether such event affects NPC or SPCC.
13.2.2 Notwithstanding Article 13.1, SPCC shall not be entitled to claim
Force Majeure for the following events:
(a) Any shutdown of the Refinery due to bankruptcy, reorganization,
or appointment of a receiver for Caltex; or
(b) Any failure by the Refinery to provide any Fuel it has
contracted with SPCC to provide, if and to the extent that such
Fuel is available elsewhere for delivery to the Project (i) for
the same price as the Fuel to have been supplied by the
Refinery (or at such higher price as NPC shall have agreed in
writing to include in the Fuel Fees) and (ii) on the same terms
and conditions as the Fuel to have been supplied by the
Refinery, or on different terms and conditions to the extent
that such terms and conditions do not increase the overall
price to SPCC (or NPC shall have agreed in writing to
compensate SPCC for the effect thereof through the Fuel Fees).
13.3 PROCEDURE. The Party invoking Force Majeure shall:
----------
(a) notify the other Party as soon as reasonably practicable by fax or
cable of the event or circumstance concerned and of the extent to
which fulfillment of its obligations is prevented, hindered or delayed
thereby;
(b) keep the other Party fully informed as to the actions taken or to be
taken by it to overcome the effects thereof, and from time to time
provides the other Party with such information and permits it such
access as the other Party may reasonably require for the purpose of
assessing such effects and the actions taken or to be taken; and
(c) resume performance of its obligations as soon as possible after the
effects thereof have been overcome or the event or circumstance no
longer exists.
42
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13.4 CONSULTATION. The Parties shall consult with each other and take all
-------------
reasonable steps to minimize the losses of either Party resulting from
Force Majeure and to minimize any overall delay or prejudice to the
Project.
13.5 EXTENSION OF TIME.
------------------
13.5.1 If a Party is prevented, hindered or delayed in the performance of
an obligation under this Agreement by Force Majeure then, subject to
the foregoing provisions of this Article 13, the time limited for
the performance of that obligations shall be extended by a period
equal to the period by which its performance was so prevented,
hindered or delayed; provided that the time limited for performance
of an obligation by NPC shall not be extended to the extent that
performance of that obligation has been prevented, hindered or
delayed by Government Force Majeure.
13.5.2 If a Party is prevented, hindered or delayed in the performance of
an obligation under this Agreement by any failure (whether or not
occasioned by Force Majeure) of the other Party to perform an
obligation under this Agreement, the time limited for the
performance of that first mentioned obligation shall be extended by
a period equal to the period by which the first mentioned Party's
performance was so prevented, hindered or delayed.
13.5.3 If a Party's performance is prevented, hindered or delayed by an
event of Force Majeure for a period in excess of 180 Days, or if any
event of Force Majeure occurs which causes material damage to the
Project or the Cogeneration Power Production Facility and such event
of damage would not ordinarily be insured against by NPC, the
Parties hereto shall meet and endeavor to agree on amendments to
this Agreement which will substantially preserve SPCC's economic
return at the least cost to NPC consistent with both Parties'
obligations under this Agreement. If the Parties are unable to come
to an agreement on appropriate amendments, the issue of how to amend
this Agreement within the stated parameters shall be resolved
according to Article 19 and, failing resolution thereunder, shall be
referred to arbitration pursuant to Article 23.
ARTICLE 14 - EXPERT
14.1 APPLICATION OF ARTICLE. The provision of this Article 14 shall apply
-----------------------
whenever a dispute cannot be settled by mutual discussion and either (a)
this Agreement specifically provides that the matter is to be referred to a
Expert for resolution or (b) the Parties agree in writing to refer the
matter in question to an Expert for resolution.
14.2 APPOINTMENT. The procedure for the appointment of an Expert shall be as
------------
follows:
14.2.1 the Party wishing to appoint or to refer a matter to an Expert shall
give notice to that effect to the other Party and, with such notice,
shall give details of the reason for the appointment of, and the
matter to be referred to, the Expert;
43
<PAGE>
14.2.2 the Parties shall meet and endeavor to agree upon a person to be the
Expert;
14.2.3 if, within twenty-one (21) Days from the date of the notice under
paragraph 14.2.1 above, the Parties have failed to agree upon an
Expert, the matter shall forthwith be referred by the Party wishing
the appointment to be made to the UNCITRAL ("the Appointor") which
shall be requested to make the appointment of the Expert within
thirty Days and, in so doing, may take such independent advice as he
thinks fit;
14.2.4 upon a Person being appointed as Expert under the foregoing
provisions, the Parties forthwith shall notify such Person of his
selection and shall request him to confirm within fourteen Days
whether or not he is willing and able to accept the appointment;
14.2.5 if such Person is either unwilling or unable to accept such
appointment, or shall not have confirmed his willingness and ability
to accept such appointment within the said period of fourteen Days,
then (unless the Parties are able to agree upon the appointment of
another Expert) the matter shall be referred (by either Party) in
the manner aforesaid to the Appointor who shall be requested to make
an appointment or (as the case may be) a further appointment and the
process shall be repeated until a Person is found who accepts the
appointment as Expert;
14.2.6 Within seven (7) Days of the appointment of the Expert, the Expert
shall designate a time and place for a hearing of the Parties on the
dispute, which time shall not be more than fourteen (14) Days after
the Expert's appointment; and
14.2.7 if there shall be any dispute between the Parties as to the
remuneration to be offered to the Expert, then such amount shall be
determined by the Appointor whose decision shall be final and
binding on the Parties.
14.3 ELIGIBILITY. Unless the Parties agree otherwise in writing, a person shall
------------
not be appointed as an Expert:
14.3.1 unless he shall be qualified by education, experience and training
to determine the matter in dispute;
14.3.2 if he has an interest or duty which would materially conflict with
his role (including being a director, officer, employee or
consultant to a Party or to any affiliate of a Party); or
14.3.3 if he is a national or permanent resident of the Philippines or of
any country in which SPCC or its shareholders (or their ultimate
holding companies) is located.
14.4 PROCEDURES.
-----------
14.4.1 The following provisions shall apply to the Expert's determination:
(a) each Party shall supply to the Expert such information as the
Expert may request;
44
<PAGE>
(b) at the time nominated for the hearing, each Party shall appear
before the Expert (with advisors of its choosing, if the Party
so desires) and present its case;
(c) the Expert shall make his decision as soon as reasonably
practicable after completion of the hearing and receipt of
data, information and submissions supplied and made to him by
the Parties not later than thirty Days after he has confirmed
to the Parties acceptance of his appointment;
(d) the Expert shall ignore any data, information or submissions
supplied and made after thirty Day period referred to in
subparagraph (c) above unless the same are furnished in
response to a specific request from him;
(e) the Expert shall be entitled to obtain such independent
professional and/or technical advice as he may reasonably
require and to obtain any necessary secretarial assistance as
is reasonably necessary; and
(f) the Expert shall give full written reasons for his decision.
14.4.2 All communications between the Parties and the Expert or the
Appointor shall be made in writing and a copy thereof provided
simultaneously to the other Party. No meeting between the Expert or
the Appointor and the Parties or either of them, shall take place
unless both Parties have a reasonable opportunity to attend any such
meeting.
14.4.3 The Expert shall be deemed not to be an arbitrator but shall render
his decision as an expert and the procedural laws relating to
arbitration shall not apply to the Expert or his determination or
the procedure by which he reaches his decision.
14.4.4 The determination of the Expert shall be final and binding upon the
Parties upon the delivery to them of the Expert's written
determination, save in the event of fraud, mistake or manifest
error.
14.4.5 Each Party shall bear the costs of providing all data, information
and submissions given by it, and the costs and expenses of all
counsel, witnesses and employees retained by it, but (unless the
Expert shall make any award of such costs and expenses which award,
if made, shall be part of the Expert's decision) the cost and
expenses of the Expert and any independent advisers to the Expert,
and any costs of his appointment if he is appointed by the
Appointor, shall be borne equally by the Parties.
14.4.6 If the Expert does not render a decision within a period of ninety
(90) Days of completion of the hearing or such longer or shorter
period as the Parties may agree in writing, either Party may, upon
giving notice to the other, terminate such appointment, and a new
Expert shall be appointed who shall resolve the dispute in
accordance with this Article 14. If the dispute is not resolved
within nine months of a Party's original notice to refer the dispute
to an Expert, or enforcement of this Article 14 or any
45
<PAGE>
decision hereunder is denied for any reason, then either Party may
refer the dispute to arbitration in accordance with Article 23.
ARTICLE 15 - SEVERAL OBLIGATIONS
Except where specifically provided otherwise in this Agreement, the duties,
obligations and liabilities of the Parties hereto are several and not joint or
collective, each Party shall be liable only for its own obligations. Nothing in
this Agreement shall be construed as creating an association, trust, partnership
or joint venture among the Parties hereto.
ARTICLE 16 - NOTICES
16.1 WRITING. Unless otherwise stated, each communication to be made hereunder
shall be made in writing.
16.2 ADDRESSES. Any communication or document to be made or delivered by one
----------
Party to another Party pursuant to this Agreement shall be made or
delivered to that other Party at the following address or fax number:
NATIONAL POWER CORPORATION
President
Quezon Avenue
Corner Agham Road
East Triangle, Diliman
Quezon City, Philippines
Fax (632) 921-2998
with a copy to:
Project Manager
Project Management and Engineering Services Group
Quezon Avenue
Corner Agham Road
East Triangle, Diliman
Quezon City, Philippines
Fax (632) 921-2998
SAN PASCUAL COGENERATION COMPANY INTERNATIONAL B.V.
Managing Director
8/F 6750 Ayala Avenue
1226 Makati, Metro Manila
Philippines
Fax (632) 892-7755
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with a copy to:
3521 CB Utrecht
The Netherlands
Croeselaan 18
Fax (31-30) 21-6944
Attention: Managing Directors
or such other address notified by that Party to the other Parties by giving not
less than 15 Days notice of such change of address, and shall be deemed
effective (i) in the case of any communication made by fax, with correct
confirmation, when dispatched to such fax number, and (ii) in the case of any
communication made by letter, when left at that address or otherwise received by
the addressee.
ARTICLE 17 - WAIVER
None of the provisions of this Agreement shall be considered waived by either
Party except when such waiver is given in writing. The failure of either Party
to insist, in any one or more instances, upon strict performance of any of the
provisions of this Agreement or to take advantage of any of its rights hereunder
shall not be construed as a waiver of any such provisions or the relinquishment
of any such rights for the future, but the same shall continue and remain in
full force and effect.
ARTICLE 18 - BENEFIT OF AGREEMENT
18.1 ASSIGNMENT BY NPC. NPC may assign or transfer all or any part of its
rights, benefits or obligations hereunder, and may merge or consolidate
with any other company which is wholly or partially owned by the Republic
of the Philippines where the surviving entity adopts and becomes fully
liable to perform NPC's obligations hereunder and such merger or
consolidation does not affect the validity and enforceability of the
Performance Undertaking.
18.2 NPC PRIVATIZATION.
------------------
18.2.1 In the event of restructuring and/or privatization of NPC in
furtherance of law or regulation coming into effect after the
signing of this Agreement, NPC may assign all or any part of its
rights and obligations under this Agreement to any person to whom
the Performance Undertaking (to the extent applicable to the
obligations assigned) is extended in respect of the obligations
assigned.
18.2.2 Except as set forth in Article 18.2.1 above, NPC has the right to
assign all or any of its rights and obligations under this Agreement
to any person or persons, provided that the assignee shall have
obtained and maintained for two Years an investment grade credit
rating from Standard & Poors or Moody's Investor Service or any
other internationally recognized rating agency for its long-term,
unsecured, unguaranteed U.S. Dollar or Japanese Yen debts.
18.3 ASSIGNMENT BY SPCC. SPCC may not, without the consent of NPC, transfer all
or any of its obligations hereunder except that, for the purposes of
arranging or
47
<PAGE>
rearranging financing for the Project, and ascending this Agreement to SPCC
Philippines, SPCC may assign or transfer to any person or entity providing
financing to the Project, all or any part of its rights and benefits
hereunder as security for the indebtedness. NPC shall duly acknowledge any
such assignment or transfer of which it is given notice and shall cooperate
in good faith in executing required documents and consents required by the
lending party or institution. SPCC shall remain jointly and severally
liable with SPCC Philippines for the obligations under this Agreement upon
the ascension by SPCC Philippines.
18.4 SPCC PHILIPPINES. The importation into the Philippines of all equipment
-----------------
for the Project and all other work in connection with the Project which
necessarily has to be performed in the Philippines and which SPCC agrees to
be responsible for hereunder shall be carried out by SPCC Philippines which
shall undertake to perform SPCC's obligations to perform such work and in
consideration of which NPC shall pay fees as provided in Part B of Article
6; for such purpose, SPCC, NPC and SPCC Philippines (whose participation
SPCC shall procure) shall execute and deliver the Accession Undertaking,
upon the effectiveness of which SPCC Philippines shall become a party
hereto without the need for any further action on the part of SPCC or NPC .
18.5 EFFECT OF ASSIGNMENT. Except as set forth in Article 18.4, no assignment
--------------------
shall be effective until the assignee has delivered to the Parties a
written undertaking (in form and content reasonably satisfactory to them)
accepting and assuming the rights and obligations to be assigned.
Thereupon, the assignor shall be relieved of its obligations to the extent
assigned except for any obligations accrued before the effective date of
the assignment. Such accrued obligations shall also become the obligations
of the assignee.
ARTICLE 19 - DISPUTE RESOLUTION
19.1 REGULAR MEETINGS. Throughout the Cooperation Period representatives of NPC
-----------------
and SPCC shall meet regularly at not less than yearly intervals, or as the
need arises, to discuss the progress of the Project and the operation of
the Cogeneration Power Production Facility in order to ensure that the
arrangement between the Parties hereto proceeds on a mutually satisfactory
basis.
19.2 AMICABLE SETTLEMENT. Without prejudice to Article 14, the Parties hereto
--------------------
agree to seek in good faith to resolve any dispute, controversy or claim
arising out of, or relating to, this Agreement, or the breach, termination
or invalidity thereof, or in the interpretation of any of the provisions
thereof by discussion. Failing such resolution, either Party may require by
notice to the other that the matter be referred to their respective senior
executives with decision making authority for resolution and each Party
shall procure that its senior executive seeks in good faith to resolve the
matter by discussion with the other. Such dispute or differences and the
joint decision of such senior executives shall be binding upon the Parties
hereto and in the event that a settlement of any such dispute or difference
is not reached pursuant to this Article 19.2 then the provisions of Article
23 shall apply.
48
<PAGE>
ARTICLE 20 - ENTIRE AGREEMENT
This Agreement constitutes or expressly refers to the entire agreement of the
Parties in respect of the subject matter hereof and all previous agreements,
arrangements, understandings and representations, express or implied and whether
oral or written are of no force and effect.
ARTICLE 21 - GOVERNING LAW
21.1 This Agreement shall be governed by and construed in accordance with the
laws of the Republic of the Philippines except such of those laws as would
direct the application of the laws of another jurisdiction. Without
prejudice to Article 23, the Parties may by mutual agreement waive the
arbitration requirements of Article 23 and, in such event, the Parties
submit to the non-exclusive jurisdiction of the proper courts of Quezon
City, Metropolitan Manila, Philippines for the hearing and determining of
any action or proceeding arising out of or in connection with this
Agreement.
21.2 Neither Party shall be relieved of any obligation under this Agreement
pending the resolution of a dispute pursuant to Articles 14 or 23 or
otherwise.
ARTICLE 22 - DISCLAIMER
Except to the extent provided in this Agreement, in no event shall either Party
be liable to the other Party for any indirect, special, incidental,
consequential or exemplary damages with respect to any claim arising out of this
Agreement, whether based upon contract, tort (including negligence), strict
liability, patent, trademark, or servicemark or otherwise.
ARTICLE 23 - ARBITRATION
Subject to Article 19.2 and without prejudice to Article 14 , any dispute,
controversy or claim arising out of or relating to, this Agreement, or the
breach, termination or invalidity thereof, shall be finally settled by
arbitration in accordance with the UNCITRAL Arbitration Rules in effect at the
time of such dispute. Arbitration under this Agreement shall be conducted by
three (3) arbitrators, each party having the power to appoint one of the
arbitrators. The third arbitrator shall be selected in accordance with the
UNCITRAL Rules, as shall either of the other two arbitrators if, after a period
of 30 Days from receipt of a written demand for arbitration, no such arbitrator
has been appointed. In the selection of any arbitrator, consideration shall be
given to the arbitrator's familiarity with power contracts and experience in
dispute resolution between parties, as a judge or otherwise. The arbitrators
shall have the authority to issue appropriate remedies including monetary
judgments and specific performance of this Agreement after taking into
consideration any appropriate amendments proposed by such arbitrators. Any
decision by the arbitrators shall be binding and non-appealable, and maybe
enforced by any court of competent jurisdiction.
The place of arbitration shall be Singapore, or such other site as may be agreed
by the Parties. The language to be used in the arbitration proceedings shall be
English.
49
<PAGE>
ARTICLE 24 - IMMUNITY
To the extent that NPC may in any jurisdiction claim for itself or its assets or
revenues immunity from suit, execution, attachment (whether in aid of execution,
before judgment or otherwise) or other legal process and to the extent that in
any such jurisdiction there may be attributed to itself or its assets or
revenues such immunity (whether or not claimed), NPC agrees not to claim and
irrevocably waives such immunity to the full extent permitted by the laws of
such jurisdiction.
ARTICLE 25 - EFFECT OF HEADINGS
Article, Part, Article, and/or paragraph headings appearing in this Agreement
are inserted for convenience only and shall not be construed as interpretation
of text.
ARTICLE 26 - SEVERABILITY
If any term of this Agreement is finally declared to be invalid by competent
courts, the other terms hereof shall not thereby be affected or impaired and
shall continue in full force and effect and the Parties shall, in good faith,
seek to negotiate valid substitute provisions which shall as nearly as possible
preserve the commercial balance between them.
ARTICLE 27 - LIABILITY
27.1 LIMIT OF LIABILITY.
-------------------
(a) Except in the case of intentional breach or gross negligence, the
liability of SPCC to NPC, to the extent the loss or damage suffered by
NPC is attributable to SPCC'S failure to achieve a Milestone or to
supply Contracted Capacity, Net Electrical Output or Ancillary
Services, or to maintain the 60% plant Thermal Efficiency in
accordance with this Agreement shall be limited to the payment of the
specific amounts mentioned in Article 3.10 and the Third Schedule and
the loss of income from application of the penalties mentioned in the
Eighth Schedule, at the times mentioned in this Agreement.
(b) Except in the case of intentional breach or gross negligence, the
liability of NPC to SPCC for any breach by it of this Agreement on or
after the Commercial Operation Date, to the extent the loss or damage
suffered by SPCC is attributable to its being prevented from supplying
Contracted Capacity, Net Electrical Output or Ancillary Services,
shall be limited to the payment of Availability Fees at the times
mentioned in this Agreement, the penalties, if any, awarded by the
Expert pursuant to Article 4.6.3 of this Agreement, and, if such
breach results in termination of this Agreement by SPCC, to the
payment of the Termination Price.
(c) Without prejudice to Article 4.7, and except in the case of
intentional breach or gross negligence, the liability of NPC for any
breach by it of this Agreement before the Commercial Operation Date,
to the extent the loss or damage suffered by SPCC is attributable to
SPCC's being delayed in
50
<PAGE>
the prosecution of the Project, shall be limited to the payment of the
reasonable additional costs and expenses incurred by SPCC as a
consequence thereof, the penalties, if any, awarded by the Expert
pursuant to Article 4.6.3 of this Agreement, and, if such breach
results in termination of this Agreement by SPCC, to payment of the
specific amounts mentioned in Article 7.5.1(b).
27.2 NPC INDEMNITY. NPC shall defend, indemnify and hold harmless SPCC, and its
--------------
officers and employees, from and against any claim of any third party for
loss, damage, cost or expense suffered as a result of any interruption of
electricity supply or any other disruption or surge of electricity supply
arising out of or in connection with this Agreement, howsoever occasioned,
and NPC shall indemnify SPCC against any loss, cost or expense resulting
from damage to the Cogeneration Power Production Facility caused or
resulting from any interruption or disruption or surge of electricity along
the Transmission Line, unless and to the extent that such loss, cost or
expense would have been avoided had any safety and protective equipment
installed on the Site by SPCC not failed to operate within the
specifications agreed between NPC and SPCC, except to the extent the result
of gross negligence or willful misconduct by SPCC.
27.3 CROSS INDEMNITY. Subject to Article 27.1 and 27.2, each of NPC and SPCC
----------------
("Indemnifying Party") shall defend, indemnify and hold harmless the other,
its directors, officers, employees and agents (including but not limited to
affiliates and contractors and their employees) from and against all
liabilities, damages, losses, penalties, claims, demands, suits, costs,
expenses (including reasonable attorney's fees and expenses) and
proceedings of any nature whatsoever for bodily injury (including death) or
property damage (but not economic loss or any other consequential damage)
that result from the performance under this Agreement by or on behalf of
that Party (including, with respect to SPCC, the engineering, design,
construction, financing, purchase, acquisition, acceptance, delivery,
ownership, possession, operation, use, leasing, maintenance, repair,
reconditioning, return, abandonment or other application or disposition of
the Cogeneration Power Production Facility and any fuel, equipment,
materials or supplies used therein, by-products (including steam, waste
products or emissions therefrom)), except to the extent that such injury
and/or any damage is attributable to the negligent or intentional act or
omission of the Party seeking to be indemnified or its directors, officers,
employees, representatives or agents); in the event such injury or damage
results from the joint or concurrent negligent or intentional act or
omission of the Parties, each shall be liable under this indemnification
for the proportion attributable to its relative degree of fault.
ARTICLE 28 - EFFECTIVE DATE AND CONDITIONS PRECEDENT
28.1 EFFECTIVE DATE
--------------
28.1.1 Within ten (10) Days from the execution of this Agreement by the
Parties, SPCC shall deliver to NPC (each in form and substance
satisfactory to NPC):
(i) copies of the memorandum and articles of incorporation of
SPCC, certified as true and correct by a director of SPCC;
51
<PAGE>
(ii) a certificate of a director of SPCC, confirming the approval
of the board of directors of SPCC to the execution, delivery
and performance of SPCC of this Agreement;
(iii) the Proponents' Agreement, duly executed by all persons (other
than NPC and SPCC Philippines), expressed to be the Party
thereto;
(iv) a certificate of a director or officer of each Proponent,
confirming the approval of the board of directors of such
Proponent to the execution, delivery and performance by such
Proponent of the Proponents' Agreement; and
(v) the Development Bond;
except to the extent waived by NPC. If SPCC fails so to deliver all
of these items, at NPC's option this Agreement shall immediately
terminate and be of no force or effect.
28.1.2 The Effective Date shall be the date on which last occurs the
following ("Conditions Precedent"):
(i) the delivery to SPCC of a certificate of the Corporate
Secretary of NPC confirming the approval of the National Power
Board to the execution, delivery and performance by NPC of
this Agreement.
(ii) the delivery to SPCC of a legal opinion of the General Counsel
of NPC in the form of set out in the Thirteenth Schedule;
(iii) Notice to Proceed issued by NPC to SPCC in the form and
substance required under Law;
(iv) the receipt by NPC and delivering to SPCC of a legal opinion
of the Secretary of Justice of the Republic of the Philippines
as to the validity, enforceability and binding effect of the
Performance Undertaking;
(v) the receipt by NPC of the registration by the Bangko Sentral
ng Pilipinas of the Build Own Operate scheme covered by this
Agreement which is required to allow NPC to purchase foreign
exchange from the Philippine banking system to service
payments due under this Agreement;
(vi) the receipt by SPCC of a Performance Undertaking of the
Republic of the Philippines in the form and terms of the
Eleventh Schedule which it requires to perform its obligations
under this Agreement;
(vii) the receipt by SPCC of an opinion of the National
Electrification Administration and the Energy Regulatory Board
confirming that the operation by SPCC of the Cogeneration
Power Production Facility will not constitute a public utility
so as to require a franchise, certificate of public
convenience or other similar license which it requires to
perform its obligations under this Agreement;
52
<PAGE>
(viii)the registration of SPCC Philippines with the Securities and
Exchange Commission of the Republic of the Philippines which
it requires to perform its obligations under this Agreement,
and delivering to NPC copies of its organizational documents,
certified as true and correct by a director of SPCC
Philippines, together with the Accession Undertaking, duly
executed by SPCC and SPCC Philippines, and a counterpart of
the Proponents' Agreement, duly executed by SPCC Philippines;
(ix) the registration of SPCC Philippines with the Board of
Investments of the Republic of the Philippines as a pioneer
enterprise under the Omnibus Investments Code of 1987 which it
requires to perform its obligations under this Agreement,
containing the conditions and the incentives which a
registered enterprise may be entitled to under the 1996
Investments Priorities Plan which SPCC has based its proposal;
and
(x) the receipt by SPCC of a notice from the Bureau of Internal
Revenue stating that SPCC has achieved a zero rating for its
sale of electricity to NPC, subject to no conditions or
qualifications;
except to the extent waived by SPCC in respect of Articles 28.1.2
(i), (ii), (iii), (iv), and (x).
28.1.3 If the Conditions Precedent mentioned in Articles 28.1.2 (i), (iii)
and (iv) have not been satisfied within three months after the
Contract Signing Date, SPCC shall have the right to terminate this
Agreement, whereupon NPC shall return the Bid Bond or Development
Bond, whichever is effective, to SPCC and this Agreement shall be of
no further force or effect. Each Party shall bear its own costs and
expenses.
28.1.4 If the Conditions Precedent mentioned in Articles 28.1.2 (v) to (ix)
above have not been satisfied within six months after the Contract
Signing Date, this Agreement shall terminate (unless the Parties
otherwise agree) and be of no further force or effect and each Party
shall bear its own costs and expenses. The Development Bond will be
returned to SPCC.
28.1.5 If the Condition Precedent mentioned in Article 28.1.2(x) above has
not been satisfied by September 30, 1997, this Agreement shall
terminate (unless such condition precedent is waived by SPCC) and be
of no further force or effect and each Party shall bear its own
costs and expenses. The Development Bond will be returned to SPCC.
28.1.6 If the Condition Precedent mentioned in Article 28.1.2 (ii) above
has not been satisfied within seven months after the Contract
Signing Date, this Agreement shall terminate (unless such condition
precedent is waived by SPCC) and be of no further force or effect
and each Party shall bear its own costs and expenses. The
Development Bond will be returned to SPCC.
28.2 CONDITIONS PRECEDENT. Until the Effective Date, except with respect to
---------------------
Article 6.14 and other than as mentioned in Article 28.1, no Party shall
have any obligation to the other. However, all the provisions of this
Agreement related to
53
<PAGE>
the full enjoyment and enforcement of the obligations mentioned in this
Article 28.1 (including those in relation to dispute resolution and giving
of the notices) shall be effective on and from the Contract Signing Date to
the extent they so relate.
28.3 TERMINATION FOR FAILURE TO OBTAIN CERTAIN GOVERNMENT APPROVALS. If SPCC
--------------------------------------------------------------
fails to obtain the final approval and registration by the Bangko Sentral
ng Pilipinas for:
(i) any bridge or other loans to be made in non-Philippine currency by the
shareholders or any other party to SPCC and for the payment of
interest thereon and the payment of the principal thereof in foreign
currency;
(ii) incurring by SPCC of non-Philippine currency debt from international
financial institutions or agencies, including International Finance
Corporation and Asian Development Bank, the Overseas Private
Investment Corporation, the Multilateral Investment Guarantee Agency,
the United States Agency for International Development, for the
purpose of repaying bridge loans (if any) extended by Shareholders or
any other party, and for meeting the balance of the capital
requirements of the Project;
(iii)repatriation of Shareholders' investment in SPCC and the profits of
such investment as allowed by the laws, rules and regulations of the
Republic of the Philippines on the date the investment is made; and
(iv) SPCC to receive payment in dollars as provided herein and to maintain
an offshore dollar account or accounts,
and such failure is not due to the fault of SPCC, then SPCC at its option
may terminate the Agreement and SPCC shall have no further liability
whatsoever hereunder and NPC shall not be entitled to draw upon any Bond.
54
<PAGE>
ARTICLE 29 - COUNTERPART EXECUTION
This Agreement may be executed in any number of counterparts which, when taken
together, shall constitute one and the same agreement.
AS WITNESS the hands of the duly authorized representatives of the Parties
- ----------
hereto on the 10th day of September, 1997.
NATIONAL POWER CORPORATION
By:
/s/ Guido Alfredo Delgado
-------------------------
GUIDO ALFREDO DELGADO
President
SAN PASCUAL COGENERATION COMPANY INTERNATIONAL B.V.
By:
/s/ Martin D. Considine /s/ Robert E. Driscoll
----------------------- ----------------------
MARTIN D. CONSIDINE ROBERT E. DRISCOLL
Managing Director Managing Director
Signed in the presence of:
/s/ Ariel C. Vinoya /s/ Patrick R. Hale
----------------------- ----------------------
55
<PAGE>
EXHIBIT 10.46
POWER PURCHASE AGREEMENT
(INITIALED COPY)
<PAGE>
Agreement regarding
Power Purchase Agreement
relating to
734 MW Power Plant in Prachuab Kiri Khan Province, Kingdom of Thailand between
Electricity Generating Authority of Thailand
and
Gulf Power Generation Company Limited
-----------------------
With regard to the Power Purchase Agreement for the 734 MW coal-fired power
plant to be located in Prachuab Kiri Khan Province (hereinafter the "Agreement")
which the Electricity Generating Authority of Thailand ("EGAT") and Gulf Power
Generation Company Limited ("GULF") are executing contemporaneously with this
letter (an execution copy of which is attached hereto), EGAT and GULF
(hereinafter referred to as the "Parties") agree as follows:
1. Unless otherwise defined herein, capitalized terms in this letter shall
have the same meaning as in the Agreement.
2. EGAT agrees that on or prior to the date that is the earlier of the
Scheduled Financial Close Date and the date of Financial Close, Section
19.1 of the Agreement and paragraph 4.1 Schedule 2 thereto, shall be
amended, if necessary, so as to extend to GULF terms that are no less
favorable than the terms and conditions associated with comparable
provisions in any other power purchase agreement executed, or subsequently
amended or supplemented by EGAT, as a result of EGAT's Request for
Proposals - 1994 Independent Power Solicitation (the "1994 Solicitation").
Notwithstanding the foregoing, GULF shall not be entitled to any such
amendments pursuant to this provision for terms which are concluded with
any other IPP project as a result of dispute resolution which has yielded a
binding decision by an expert or by arbitration under or in connection with
any power purchase agreement.
3. After the execution of this letter, subject to paragraph 2 hereof, GULF
shall not claim any relief from its obligations under the Agreement on the
basis of Force Majeure or Governmental Force Majeure due to issuance by the
Thailand Ministry of Finance of a notification on 2 July 1997 providing
that the value of the Thai Baht will be set by conditions in the foreign
exchange markets (the "Notification"). Other than amendments to the
Agreement in accordance with paragraph 2 hereof, there shall not be any
revisions to the Agreement with respect to the issuance of the Notification
or the adoption of the managed float of the Thai Baht thereunder.
4. EGAT agrees that, at all times prior to the date which is the earlier of
the Scheduled Financial Close Date and the date of Financial Close, the
terms of this Agreement and Schedules thereto shall be amended, if
necessary, so as to extend to GULF terms (other than terms which are
related to a power project's specific technical characteristics) no less
favorable to GULF than the terms and conditions included in any other Stage
2 power purchase agreement executed, or subsequently amended or
supplemented, by EGAT in connection with the 1994 Solicitation (commonly
referred to as Stage 2 of Round One of EGAT's IPP Program) with respect to:
a. the rights of the Generator or the obligations of EGAT regarding any
compensation to be paid by EGAT as a result of the termination of the
Agreement following a default by EGAT;
b. the list and definitions of Force Majeure and Governmental Force
Majeure;
<PAGE>
c. except with regard to the period of time Force Majeure must continue
before EGAT may exercise its termination rights under Section 14.6.2
of the Agreement, the termination rights in respect of, or the nature
or categories of compensation to be paid to a power producer in the
event of, the occurrence and continuation of an event of Force Majeure
or Governmental Force Majeure or the factors or procedures for
determining such compensation; and
d. the method of payment set forth in Section 19.3 of the Agreement.
5. EGAT agrees to extend to GULF material revisions in the manner in which the
application of Schedule 2 is administered with regard to any other power
purchase agreement for coal fired generation that is executed by EGAT as a
result of the 1994 Solicitation, provided such revisions are not related to
power project specific technical characteristics and (i) remedy demonstrated
problems with the administration of Schedule 2 and are of a generic nature
which warrant application to all of the power purchase agreements for coal
fired generation that have been executed by EGAT as a result of the 1994
Solicitation, and (ii) would restrict the application of or limit GULF's
exposure to the DRA, DDF and DSN deductions set forth in Schedule 2 of this
Agreement.
6. The Parties shall confer together in good faith concerning appropriate
accounting and tax treatment for the New Transmission Facilities and
documentation related thereto, including potential amendments to the
Agreement, if applicable.
7. The Parties agree that this letter and the Agreement together contain or
expressly refers to the entire Agreement between the Parties with respect
to the subject matter addressed thereby. Each of the Parties acknowledges
and confirms that it does not enter into this letter or the Agreement in
reliance on, and the Parties expressly waive any rights associated with, any
representation, warranty, commitment, obligation or other undertaking by the
other Parties not expressly reflected in this letter and the Agreement. Any
dispute under or concerning this letter shall be resolved in accordance with
Section 15 of this Agreement, which are incorporated by reference herein.
Acknowledged and agreed as of the date set forth below
On behalf of the On behalf of the
ELECTRICITY GENERATING GULF POWER GENERATION
AUTHORITY OF THAILAND (EGAT) COMPANY LIMITED (GULF)
By: By:
------------------------- --------------------------
(Mr. Viravat Chlayon) (Mr. Sarath Ratanavadi)
Governor Director
December 1997 December 1997
Bangkok, Thailand Bangkok, Thailand
By:
--------------------------
(Mr. Gerard P. Loughman)
Director
December 1997
Bangkok, Thailand
<PAGE>
CONTRACT NO. IPP/ 41-107
POWER PURCHASE AGREEMENT
BETWEEN
GULF POWER GENERATION COMPANY LIMITED
AND
ELECTRICITY GENERATING AUTHORITY OF THAILAND
SIGNED ON DECEMBER 22, 1997
<PAGE>
CONTENTS
<TABLE>
<CAPTION>
SECTION PAGE
<S> <C>
1. DEFINITIONS AND INTERPRETATIONS.................................................... 2
1.1 Definitions.................................................................. 2
1.2 Interpretation............................................................... 12
1.3 Calculation Values........................................................... 13
1.4 Table of Contents and Headings............................................... 13
2. FACILITY DEVELOPMENT AND CONNECTION ARRANGEMENTS................................... 13
2.1 Obligations to Construct..................................................... 13
2.2 Construction and Licensing of the Facility................................... 13
2.3 Independent Engineer and Progress Reports on Construction.................... 14
2.4 Metering..................................................................... 15
2.5 Grid Code Equipment and Communication Requirements........................... 17
2.6 Rights-Of-Way and Easements.................................................. 17
2.7 Provision of Information and Consultation Relating to EGAT
Transmission Facilities...................................................... 18
2.8 Completion of New Transmission Facilities.................................... 18
2.9 Inspection and Energizing of the Connection Point and Facility
Switchyard................................................................... 21
2.10 Synchronizing and Commercial Operation....................................... 22
2.11 Testing...................................................................... 24
2.12 Review by EGAT............................................................... 26
3. PROVISION AND PURCHASE OF AVAILABILITY AND
ELECTRICITY........................................................................ 26
3.1 Obligation to Provide Dependable Contracted Capacity and Contracted
Operating Characteristics.................................................... 26
3.2 Compliance with the Grid Code................................................ 27
3.3 Sale and Purchase of Electricity............................................. 27
3.4 Provision of Standby Service................................................. 28
3.5 Dispatch Instructions........................................................ 28
3.6 Operation and Maintenance (O&M) Reports...................................... 28
4. DELIVERY OF ELECTRICITY............................................................ 28
4.1 Quality of Supply............................................................ 28
4.2 Title and Risk of Loss....................................................... 29
4.3 Failure of the System........................................................ 29
</TABLE>
Page i
<PAGE>
<TABLE>
<S> <C>
5. AVAILABILITY PAYMENTS............................................................ 29
5.1 Calculation of Availability Payments....................................... 29
5.2 Confirmation and Payment of Availability Payments.......................... 29
5.3 Notices of Availability and Declared Operating Characteristics............. 29
6. ENERGY PAYMENTS.................................................................. 30
6.1 Entitlement to and Calculation of Energy Payments.......................... 30
6.2 Confirmation and Payment of Energy Payments................................ 30
7. MINIMUM TAKE..................................................................... 30
8. ENVIRONMENTAL QUALITY REQUIREMENTS............................................... 32
9. FUEL SUPPLY...................................................................... 32
9.1 Fuel Supply Obligations.................................................... 32
9.2 Subsequent Fuel Supply Agreements.......................................... 33
9.3 Fuel Stock................................................................. 33
10. CRITICAL DATES AND DURATION OF AGREEMENT......................................... 34
10.1 Initial Term............................................................... 34
10.2 Survival of Rights on Termination.......................................... 34
10.3 Extension of Agreement..................................................... 34
10.4 Critical Dates............................................................. 34
10.5 Extension of Critical Dates and Term....................................... 35
11. CONTRACTED MILESTONES............................................................ 35
12. DEFAULT AND TERMINATION.......................................................... 36
12.1 Termination by the Generator............................................... 36
12.2 Termination by EGAT........................................................ 37
12.3 Step-In Rights............................................................. 39
12.4 Other Rights to Terminate.................................................. 42
13. SECURITIES AND LIQUIDATED DAMAGES................................................ 42
13.1 Establishment of Development Security...................................... 42
13.2 EGAT's Right to Retain Development Security as Liquidated Damages.......... 42
13.3 Liquidated Damages for Contracted Capacity Deficiencies.................... 44
13.4 Payments from the Security................................................. 44
13.5 Additional Security........................................................ 44
13.6 Reasonable Liquidated Damages.............................................. 46
</TABLE>
Page ii
<PAGE>
<TABLE>
<S> <C>
14. FORCE MAJEURE.................................................................. 46
14.1 Overview................................................................ 46
14.2 Notice of Force Majeure and Consequences................................ 47
14.3 Limitations............................................................. 48
14.4 Payment Rights and Obligations During Force Majeure..................... 48
14.5 Payments During Extension of Term....................................... 51
14.6 Termination............................................................. 52
14.7 Reconstruction.......................................................... 53
15. DISPUTE RESOLUTION............................................................. 54
15.1 Resolution.............................................................. 54
15.2 Arbitration............................................................. 54
16. LIMITATION OF LIABILITY........................................................ 56
16.1 Indemnification......................................................... 56
16.2 Consequential Damages................................................... 57
17. CHANGE-IN-LAW.................................................................. 57
17.1 Tax Change Adjustment................................................... 57
17.2 Change-in-Law Adjustment................................................ 58
17.3 BOI Privileges.......................................................... 60
18. CONFIRMATION STATEMENT......................................................... 60
18.1 Confirmation of Availability and Metered Energy......................... 60
18.2 Access to Information................................................... 60
18.3 Review of Confirmation Statement and Meter Reconciliation Statement..... 60
18.4 Disputes................................................................ 61
18.5 Final Confirmation Statement............................................ 61
18.6 Disputes Limitation..................................................... 61
18.7 Effect of Confirmation Statement........................................ 61
18.8 Energy Payment Adjustments.............................................. 61
18.9 Interference with Metering.............................................. 62
19. BILLING AND PAYMENT............................................................ 62
19.1 Payment Invoice/Credit Note............................................. 62
19.2 Other Payments.......................................................... 63
19.3 Payment Procedure....................................................... 63
19.4 Application of Payments................................................. 63
</TABLE>
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19.5 Interest.................................................................. 64
19.6 Disputed Items............................................................ 64
19.7 Taxes and Fines........................................................... 64
19.8 Set-Off................................................................... 65
20. INDEXATION....................................................................... 65
21. CONFIDENTIALITY AND ANNOUNCEMENTS................................................ 66
21.1 General Restrictions on the Parties....................................... 66
21.2 Exceptions................................................................ 66
21.3 Internal Procedures....................................................... 67
21.4 Public Announcements...................................................... 67
22. INSURANCE AND INDEMNITIES........................................................ 67
22.1 Insurance Required........................................................ 67
22.2 Endorsements.............................................................. 68
22.3 Certificates Required..................................................... 68
22.4 Application of Proceeds................................................... 69
23. REPRESENTATIONS AND WARRANTIES................................................... 69
24. EQUITY UNDERTAKING............................................................... 71
24.1 Restrictions on Transferability........................................... 71
24.2 Qualifications to Equity Transfer Restrictions............................ 71
25. MISCELLANEOUS PROVISIONS......................................................... 72
25.1 Amendments................................................................ 72
25.2 Waivers of Rights......................................................... 72
25.3 Notice.................................................................... 72
25.4 Assignment................................................................ 73
25.5 Effect of Illegality...................................................... 74
25.6 Entire Agreement.......................................................... 75
25.7 Counterparts.............................................................. 75
25.8 Currency.................................................................. 75
25.9 Language.................................................................. 75
25.10 Third Parties............................................................. 75
25.11 Inconsistencies and Conflicts............................................. 75
26. GOVERNING LAW AND JURISDICTION................................................... 76
26.1 Governing Law.............................................................. 76
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26.2 Waiver.................................................................... 76
26.3 Arbitration............................................................... 76
27. PRIVATIZATION OF EGAT............................................................ 76
28. PERMISSION UNDER EGAT ACT........................................................ 76
SIGNATURES....................................................................... 77
</TABLE>
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THIS AGREEMENT (the AGREEMENT) is made on this 22 day of December, 1997
BETWEEN
(1) GULF POWER GENERATION CO., LTD., incorporated under the laws of Thailand,
represented by Mr. Sarath Ratanavadi, Director and Mr. Gerard P. Loughman,
Director, with its registered address at 11th Floor, M. Thai Tower 1, All
Seasons Place, 87 Wireless Road, Lumpini, Phatumwan, Bangkok 10330,
Thailand (the GENERATOR); and
(2) ELECTRICITY GENERATING AUTHORITY OF THAILAND, represented by Mr. Viravat
Chlayon, Governor, with its registered address at 53 Charansanitwong Road,
Bang Kruai, Nonthaburi 11130, Thailand (EGAT).
The Generator and EGAT are also each referred to herein as a PARTY and
collectively as the PARTIES.
WHEREAS:
(A) The Government of Thailand has announced the policy of encouraging and
promoting the development of independent power producers for generating
electricity to meet electricity demands in Thailand.
(B) To advance such Governmental policy, EGAT and the Generator have entered
into this Agreement setting out the terms on which the Generator has agreed
to develop, construct, finance, operate and maintain a 734 MW coal-fired
electricity generating plant at Boh Noak Subdistrict, Kui Buri District,
Prachuab Khiri Khan Province, Thailand to provide electricity to EGAT in
accordance with the terms and conditions of this Agreement.
NOW IT IS HEREBY AGREED as follows:
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1. DEFINITIONS AND INTERPRETATIONS
1.1 DEFINITIONS
Unless otherwise defined herein, capitalized terms used herein shall have
the following meanings, whether used in the singular or in the plural:
ACCESS RIGHTS This term shall have the meaning assigned thereto
in Section 2.6.1;
ACTUAL AVAILABILITY The Availability (in MWh) provided by a Unit during
a Settlement Period or other period as the context
requires, determined in accordance with Schedule 2;
ADDED FACILITY CHARGE This term shall have the meaning assigned thereto
in Section 2.8.16;
AFFILIATE When applied to a Person, any other Person
controlling, controlled by or under common control
with such first-named Person, provided that (i) for
purposes of Section 24, any Person that owns
directly or indirectly securities having fifty
percent (50%) or more of the voting power for the
election of directors or other governing body of a
corporation or fifty percent (50%) or more of the
partnership or other ownership interests of any
other Person (other than as a limited partner of
such Person) will be deemed to control such
corporation or other Person, and (ii) for any
purpose other than Section 24, any Person that owns
directly or indirectly securities having ten
percent (10%) or more of the voting power for the
election of directors or other governing body of a
corporation or ten percent (10%) or more of the
partnership or other ownership interests of any
other Person (other than as a limited partner of
such Person) will be deemed to control such
corporation or other Person;
AGREEMENT This Power Purchase Agreement and the Schedules
hereto;
AVAILABILITY The capability of a Unit (in MWh) to provide
generating capacity and electricity to EGAT,
regardless of the level at which EGAT dispatches
the Unit, and AVAILABLE shall be construed
accordingly;
AVAILABILITY NOTICE A statement in the form set out in Schedule 15
declaring or revising the capability of a Unit to
provide (i) generating capacity up to its
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Dependable Contracted Capacity, and (ii) the
other Contracted Operating Characteristics set
out in Paragraph 2 of Schedule 1;
AVAILABILITY PAYMENT Payment made by EGAT to the Generator for the
Actual Availability provided by the Units as
determined in accordance with Schedule 2;
BACK-UP METERING EQUIPMENT The back-up metering equipment and associated
devices as described in Schedule 13;
BAHT The lawful currency of the Kingdom of Thailand;
BILLING PERIOD The period beginning on the Commercial Operation
Date of the First Unit and ending on the last day
of the month in which that date occurs, each full
month in a Contract Year, and the period
beginning on the first day of the month in which
the Term expires and ending on the day the Term
expires;
BTU British Thermal Units;
BUSINESS DAY Any weekday from Monday through Friday, excluding
in each calendar year (i) not more than sixteen
(16) holidays designated by EGAT no later than
December 20 of the preceding year, and (ii) any
other holidays designated by the Bank of Thailand
for such calendar year;
CHANGE-IN-LAW Any of the following events occurring after the
Execution Date as a result of any action by any
Governmental Authority: (i) a change in or repeal
of an existing Law, (ii) an enactment or making
of a new Law, and (iii) a change in the manner in
which a Law is applied or in the application or
interpretation thereof (including any
interpretation of environmental standards);
COMMERCIAL OPERATION DATE The date agreed by EGAT and the Generator in
accordance with Section 2.10.2 with respect to
each Unit;
COMMERCIAL OPERATIONS TEST The series of tests to determine the net
generating capacity and Operating Characteristics
of a Unit as set out in Schedule 14;
CONFIRMATION STATEMENT A statement in the form set out in Schedule 15
confirming the capability of a Unit to provide
(i) generating capacity up to its Dependable
Contracted Capacity, and (ii) the other
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Contracted Operating Characteristics set out in
Paragraph 2 of Schedule 1;
CONNECTION The link between the Facility and the EGAT
System;
CONNECTION POINT The physical point or points where the Facility
and the New Transmission Facilities are
connected, which shall be the takeoff structure
in the Facility switchyard, as identified in
Schedules 10 and 13;
CONTRACTED AVAILABLE HOURS This term shall have the meaning
assigned thereto in Schedule 2;
CONTRACTED CAPACITY The rated net power output (expressed in MW) of
each Unit as set out in Schedule 1;
CONTRACTED OPERATING The Operating Characteristics of each Unit as set
CHARACTERISTICS out in Schedule 1, exclusive of Paragraph 3.2
thereof;
CONTRACT YEAR For the first calendar year of the Facility's
operation, the period which begins on the
Commercial Operation Date of the First Unit and
ends on December 31, and thereafter during the
Term, each annual period commencing on January 1
and ending on December 31 (or on the last day of
the Term);
CONTROL For purposes of Section 27.1, control of any
Person by a Governmental Authority shall mean
direct or indirect ownership by such Governmental
Authority of fifty percent (50%) or more of the
securities having ordinary voting power for the
election of directors or other governing body
(for a corporation) or fifty percent (50%) or
more of a partnership interest (excluding
interests as a limited partner) or other
ownership interests of another Person;
DECLARED OPERATING The Operating Characteristics of a Unit as
CHARACTERISTICS declared from time to time in accordance with
Schedule 2;
DEFAULT RATE A rate equal to two percent (2%) over the
Overdraft Rate;
DEPENDABLE CONTRACTED The maximum continuous net generating capacity of
CAPACITY a Unit (measured in MW or kW as appropriate)
established in accordance with Section 2.11;
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DESIGN LIMITS The operational limits of a Unit as set out in
Schedule 1 and revised from time to time as agreed
by the Parties;
DEVELOPMENT SECURITY A direct pay letter of credit or letter of
guarantee from one or more Thai banks or a cash sum
held by an escrow agent provided to EGAT by the
Generator in accordance with Section 13.1;
DISPATCH The direction by EGAT's Control Center to commence,
increase, decrease, continue or cease the delivery
of electricity into the EGAT System;
DISPATCH INSTRUCTION An instruction issued by EGAT's Control Center to
the Generator pursuant to the Grid Code to perform
one or more of the Declared Operating
Characteristics or other operation permitted by
this Agreement or the Grid Code;
EARLIEST COMMERCIAL The dates set out in Section 10.4 with respect to
OPERATION DATE each Unit (or as adjusted in accordance with
Section 10.5) on or after which the Unit may begin
commercial operation pursuant to Section 2.10.2;
EGAT The Electricity Generating Authority of Thailand;
EGAT ACT The Electricity Generating Authority of Thailand
Act, B.E. 2511, as amended from time to time;
EGAT'S CONTROL CENTER EGAT's National or Regional Control Centers set up
for the purposes of Dispatch of generating units,
external interconnectors and the EGAT System;
EGAT SYSTEM The bulk power network controlled or used by EGAT
for the purpose of generating, transmitting and
distributing electricity to EGAT's customers;
EMERGENCY CONDITIONS A condition or situation that in EGAT's reasonable
judgment is likely to cause (i) an imminent
physical threat of danger to life, health or
property, or (ii) a significant disruption on the
EGAT System that would adversely affect EGAT's
ability to meet its obligation to provide safe,
adequate and reliable supply of electricity to its
customers;
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ENERGIZING DATE The date determined in accordance with Section
2.10.1 on which the Connection is energized for the
pre-operation testing and start up of the First
Unit;
ENERGY PAYMENT Payment made by EGAT to the Generator for the
electrical energy generated by a Unit and delivered
to the EGAT System as determined in accordance with
Schedule 3;
EPC CONTRACT The agreement or agreements for the engineering,
design, supply, construction, erecting and testing
of the Facility, as modified or supplemented from
time to time;
EVENT OF DEFAULT An event, condition or circumstance described in
Section 12.1.1 or 12.2.1;
EXECUTION DATE The date on which this Agreement is signed by the
Parties;
EXPERT Any person appointed by agreement between the
Parties pursuant to Section 15.1.2;
FACILITY The two Units and the Generator's associated
buildings, structures, roads, and other
appurtenances, not including the New Transmission
Facilities;
FACILITY SWITCHYARD The Facility's 500kV equipment, including the Unit
auxiliary transformer, associated buildings,
structures, roads and other related appurtenances;
FINAL CONFIRMATION This term shall have the meaning assigned thereto
STATEMENT in Section 18.5;
FINANCIAL CLOSE When all relevant Financing Documents required to
fund fully the development, acquisition,
construction, ownership, and initial working
capital for the Facility have been duly executed
and either (i) an initial funding thereunder has
occurred, or (ii) EGAT shall have received a
certificate of the lead bank, agent or trustee
acting for the Financing Parties (or any other
evidence reasonably satisfactory to EGAT)
confirming that all conditions precedent to the
initial drawdown of funds thereunder have been
satisfied or waived by the Financing Parties where
the Generator does not need to make a drawdown of
funds thereunder to so fund the Facility;
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FINANCING DOCUMENTS The agreements for the making available of any
loans, credit facilities, notes (including floating
rate notes and commercial paper), bonds,
subordinated debt or other funds other than equity
or equity-related funds and including working
capital and any letters of credit (and related
agreements), security agreements, swap agreements,
and any other hedging agreements and any other
documents relating to the financing or refinancing
of the New Transmission Facilities or the Access
Rights and of the development, construction,
acquisition, ownership, operation and maintenance
of the Facility;
FINANCING PARTIES Any Person which provides loans or other financing
to the Generator as evidenced by or pursuant to the
Financing Documents;
FIRST UNIT The first of the two Units to be installed in
accordance with the schedule set out in Section
10.4;
FORCE MAJEURE This term shall have the meaning assigned thereto
in Section 14.1.1;
FUEL Coal which meets the specifications set out in the
Fuel Purchase Agreement;
FUEL PURCHASE AGREEMENT The Fuel sales contract between the supplier of
Fuel and the Generator;
FUEL STOCK The stock of Fuel to be arranged by the Generator
in accordance with Section 9.3;
FUEL TRANSPORTATION The agreement executed by the Generator to
AGREEMENT transport Fuel to the Site if arrangements for such
transport are not fully provided for in the Fuel
Purchase Agreement;
GENERATOR This term shall have the meaning assigned thereto
in the opening recitals of this Agreement;
GJ Gigajoule;
GOVERNMENTAL APPROVAL Any approval, consent, concession, decree, permit,
waiver, exemption or approval from, or filing with,
or notice to, any Governmental Authority;
GOVERNMENTAL AUTHORITY The Government of Thailand and any ministry,
department, political subdivision,
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instrumentality, agency, authority (excluding EGAT
or any successor to EGAT's interests under this
Agreement), corporation or commission under the
direct or indirect control of the Government of
Thailand, or the Parliament of Thailand, or any
court or tribunal in Thailand;
GOVERNMENTAL FORCE This term shall have the meaning assigned thereto
MAJEURE in Section 14.1.2;
GRID CODE The code issued by EGAT and attached hereto as
Schedule 20, which sets forth certain requirements
with respect to the coordination of power
facilities with the operation of the EGAT System,
and as it may be amended, modified or supplemented
from time to time;
INDEPENDENT ENGINEER The engineering firm appointed by the Generator in
accordance with Section 2.3.1;
KW Kilowatt;
KWH Kilowatt-hour;
LAW Any legislation, statute, act, Royal decree, rule,
order, treaty, regulation or announcement
(excluding the Grid Code), or any interpretation
thereof, which has been enacted, issued or
promulgated by any Governmental Authority;
METERING EQUIPMENT The Primary Metering Equipment and Back-Up Metering
Equipment as described in Schedule 13;
METERING POINT The point on the Site where the Metering Equipment
is located, as further described in Schedule 13;
METER RECONCILIATION A report issued in accordance with Section 18.1
STATEMENT following any meter test conducted pursuant to
Section 2.4.3;
MINIMUM TAKE LIABILITY This term shall have the meaning assigned thereto
in Section 7;
MW Megawatt;
MWH Megawatt-hour;
NET CAPACITY TEST The test to determine the net generating capacity
of a Unit as set out in Schedule 14;
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NET ELECTRICAL GENERATION For any period, the net electrical energy delivered
by the Facility or a Unit as the context requires
(measured in kWh or MWh as appropriate at the
Metering Point) into the EGAT System during such
period;
NEW MAIN TRANSMISSION The 500 kV double circuit transmission line from
LINE (NMTL) Bang Saphan to the NTF Connection Point and from
the NTF Connection Point to Chom Bung to be
constructed by EGAT;
NEW TRANSMISSION Extensions and modifications to the EGAT System as
FACILITIES (NTF) described in Schedule 10 made in order to allow
connection of the Facility to the EGAT System;
NOTICE A statement or notice in one of the forms set out
in Schedule 15 declaring, revising or confirming
the capability of a Unit to provide its Contracted
Operating Characteristics;
NTF CONNECTION POINT The physical point or points where the New
Transmission Facilities and the New Main
Transmission Line are connected, as identified in
Schedule 10;
NTF COMMISSIONING The date determined in accordance with Section
COMPLETION DATE 2.8.14 on which the New Transmission Facilities
have successfully completed the final testing and
commissioning requirements set out in Schedule 18;
NTF ENERGIZING DATE The date determined in accordance with Section
2.8.10 on which the NTF Connection Point is
energized;
O&M AGREEMENT The operation and maintenance agreement for the
Facility between the Generator and the Facility
operator;
OPERATING CHARACTERISTICS The parameters which define the capability of a
Unit to respond to Dispatch Instructions;
OUTAGE NOTICE A statement in the form set out in Schedule 15
declaring or revising the period during which a
Unit shall be withdrawn from service and the degree
to which this affects the Unit's capability to
deliver its Contracted Operating Characteristics,
as described in Schedule 2;
OVERDRAFT RATE The minimum overdraft rate then in effect at Krung
Thai Bank Public Company Limited, or its successor;
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PARTY This term shall have the meaning assigned thereto
in the recitals of this Agreement;
PAYMENT INVOICE/ A statement in the form set out in Schedule 6
CREDIT NOTE issued by the Generator in accordance with Section
19.1;
PERSON Any individual, corporation, partnership, joint
venture, association, trust, unincorporated
organization, Governmental Authority or other
entity;
PLANNED OUTAGE Any period during which a Unit is wholly or
partially withdrawn from service as determined in
accordance with the Grid Code;
POST EVENT NOTICE A statement given by EGAT in the form set out in
Schedule 15 describing a failure by a Unit to
deliver the Contracted Operating Characteristics
declared in a previous Notice;
PRIMARY METERING The Primary Metering Equipment and associated
EQUIPMENT devices as described in Schedule 13;
PROJECT The design, development, construction, financing,
ownership, operation and maintenance of the
Facility under the terms of this Agreement;
PROJECT AGREEMENTS The EPC Contract, the Fuel Purchase Agreement, the
Fuel Transportation Agreement (if any), the
Financing Documents, the O&M Agreement, and the
Site Agreement;
PRUDENT UTILITY PRACTICES The practices, methods and acts engaged in or
accepted by a significant portion of the
international electric generating industry for
facilities or equipment similarly situated to the
Facility, the New Transmission Facilities or the
New Main Transmission Line that, at a particular
time, in the exercise of reasonable judgment in
light of the facts known or that reasonably should
have been known at the time a decision was made,
would be expected to accomplish the desired result
in respect of the design, engineering,
construction, operation and maintenance of the
facilities or equipment associated with the
Facility, the New Transmission Facilities or the
New Main Transmission Line, in a manner consistent
with Law, Governmental Approvals, reliability,
safety, economy, environmental protection and the
construction, operation and maintenance
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standards recommended by the Facility's equipment
suppliers and manufacturers;
SCHEDULED COMMERCIAL The date set out in Section 10.4 with respect to
OPERATION DATE each Unit (or as adjusted in accordance with
Section 10.5) on which the Unit is scheduled to
begin commercial operation;
SCHEDULED CONSTRUCTION The date set out in Section 10.4 (or as adjusted in
COMMENCEMENT DATE accordance with Section 10.5) on which the
Generator is scheduled to commence construction of
the Facility in accordance with Section 11(i);
SCHEDULED ENERGIZING DATE The date set out in Section 10.4 (or as adjusted in
accordance with Section 10.5) on which the
Connection is scheduled to be energized by EGAT for
the pre-operation testing and start up of the First
Unit;
SCHEDULED FINANCIAL The date set out in Section 10.4 by which the
CLOSE DATE Generator is scheduled to complete the Financial
Close of the Project;
SCHEDULED NTF ENERGIZING The date set out in Section 10.4 (or as adjusted in
DATE accordance with Section 10.5) on which the NTF
Connection Point is scheduled to be energized by
EGAT for the testing and commissioning of the New
Transmission Facilities;
SECOND UNIT The second of the two Units to be installed in
accordance with the schedule set out in Section
10.4;
SETTLEMENT PERIOD A period of one (1) hour starting on the hour;
SITE The plot of land upon which the Facility is
located;
SITE AGREEMENT The purchase or lease agreement(s) relating to the
Generator's acquisition of a right to occupy and
use the Site for the Project;
SPONSORS Gulf Electric Company Limited (60%) and MEC
International B.V. (40%);
TAXES Any tax, charge, tariff, duty or fee of any kind
charged, imposed or levied, directly or indirectly,
by any Governmental Authority, including any VAT,
sales tax, stamp duty, import duty, withholding tax
(whether on income, dividends, interest payments,
fees,
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equipment rentals or otherwise), tax on foreign
currency loans or foreign exchange transactions,
excise tax, property tax, registration fee or
license, water tax or environmental, energy or fuel
tax (including any fee or charge imposed or
assessed on the basis of the carbon or calorific
content of fuel);
TERM The period of this Agreement as specified in
Section 10.1, subject to extension in accordance
with Sections 10.3 and 10.5;
UNIT Either of the Facility's two electrical generating
sets, each comprising a coal-fired boiler and a
steam turbine generator and ancillary equipment and
facilities as described in Schedule 7; and
VAT The value added tax in Thailand or such other taxes
having the same effect.
1.2 INTERPRETATION
In this Agreement (including its Schedules), unless otherwise stated:
1.2.1. Any references to:
(a) the Grid Code, or any section, appendix or other provision
thereof, shall be construed, at any particular time, as
including a reference to the Grid Code, section, appendix or
the relevant provision thereof as it may have been amended,
modified or supplemented;
(b) any agreement (including this Agreement or any Schedule hereto)
shall be construed, at any particular time, as including a
reference to the relevant agreement as it may have been
amended, modified, supplemented or novated;
(c) a month shall be construed as a reference to a calendar month;
(d) a particular Section or Schedule shall be a reference to the
relevant Section or Schedule in or to this Agreement; and
(e) a particular paragraph or sub-paragraph, if contained in a
Schedule, shall be a reference to the relevant paragraph or
sub-paragraph of that Schedule.
1.2.2 Words in the singular may be interpreted as referring to the plural
and vice versa, and words denoting natural persons may be
interpreted as referring to corporations and any other legal
entities and vice versa.
1.2.3. Whenever this Agreement refers to a number of days, such number
shall refer to the number of calendar days unless Business Days are
specified. A requirement that a payment be made on a day which is
not a Business Day shall be construed as a requirement that the
payment be made on the next following Business Day.
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1.2.4. The words "include" and "including" are to be construed as being at
all times followed by the words "without limitation", unless the
context otherwise requires.
1.3 CALCULATION VALUES
For the purposes of this Agreement, amounts and values shall be calculated
to the number of decimal places indicated in Schedule 4 unless otherwise
specified herein.
1.4 TABLE OF CONTENTS AND HEADINGS
The table of contents and headings are inserted for convenience only and
are not to be applied for purposes of construction and interpretation of
this Agreement.
2. FACILITY DEVELOPMENT AND CONNECTION ARRANGEMENTS
2.1 OBLIGATIONS TO CONSTRUCT
2.1.1 The Generator shall design, engineer, construct, test and
commission the Facility and the New Transmission Facilities. The
Generator shall ensure that the New Transmission Facilities and the
Facility Switchyard shall be ready for energizing on or before the
Scheduled Energizing Date, and that the First Unit and Second Unit
shall be ready for Dispatch on or before their respective Scheduled
Commercial Operation Dates.
2.1.2 EGAT shall design, engineer, construct, test, and commission the
New Main Transmission Line. EGAT shall energize the NTF Connection
Point on or before the Scheduled NTF Energizing Date for testing
and commissioning of the New Transmission Facilities and the
Facility Switchyard, and to enable Dispatch of the First Unit and
Second Unit on or before their respective Scheduled Commercial
Operation Dates.
2.2 CONSTRUCTION AND LICENSING OF THE FACILITY
The Parties shall comply with the following provisions.
2.2.1 The Generator shall apply for, obtain, and maintain, at its own
expense, each Governmental Approval necessary for the Generator to
construct, own, and operate the Facility and otherwise perform its
obligations under this Agreement. EGAT shall, when reasonably
requested by the Generator and at the Generator's cost, provide
reasonable assistance to the Generator in obtaining, renewing and
maintaining such Governmental Approvals. Notwithstanding the
foregoing, the Generator shall be solely responsible for obtaining
such Governmental Approvals. Subject to its regulatory and
statutory discretion, EGAT shall grant to the Generator any
approvals, consents, concessions, decrees, waivers, privileges or
exemptions that EGAT is empowered to grant, provided the Generator
(i) is in compliance with its obligations under this Agreement, and
(ii) has met all applicable requirements for such grant.
2.2.2 The Generator shall commence the construction of the Facility on or
before the Scheduled Construction Commencement Date.
2.2.3 The Facility shall be constructed to meet the Contracted Operating
Characteristics set out in Schedule 1, the technical
characteristics set out in
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Schedule 7 and the construction schedule set out in Schedule 11.
The Generator shall obtain EGAT's prior written consent to any
material modifications in such technical characteristics, which
consent shall not be unreasonably withheld or delayed. If EGAT does
not respond to a request for such a material modification within
thirty (30) days of receipt of such request, EGAT shall be deemed
to have given its consent to the material modification.
2.2.4 The Generator shall construct, complete, repair and modify the
Facility such that it shall, at all times, operate in compliance
with all applicable Laws, including environmental Laws, and the
Grid Code.
2.2.5 The Generator shall construct the Facility, either by itself or
through third party contractors, according to Prudent Utility
Practices and in a workmanlike and professional manner.
2.2.6 The Generator shall allow representatives of EGAT to inspect the
construction site at any reasonable time during construction,
start-up, and testing of the Facility, provided that EGAT shall
notify the Generator in writing reasonably in advance of any
inspection and shall cooperate with the Generator to minimize
interference with the Generator's contractors at the Site.
2.2.7 The Parties shall cooperate with each other in accordance with the
terms of this Agreement in the construction of the Facility, the
New Transmission Facilities and in connecting the Facility to the
EGAT System.
2.3 INDEPENDENT ENGINEER AND PROGRESS REPORTS ON CONSTRUCTION
The Generator, at its expense, shall provide EGAT with the documents and
other materials set out below within the dates specified there.
2.3.1 Within thirty (30) days after the Execution Date, the Generator
shall provide EGAT with a list of five or more independent
engineers. If at least three of the engineers listed are not
reasonably acceptable to EGAT then, within fifteen (15) days of
receiving the list (or any further lists required hereunder), EGAT
may require the Generator to provide a further list and the
Generator shall comply with any such requirement. Within fifteen
(15) days of receiving a list containing at least three independent
engineers reasonably acceptable to EGAT, EGAT shall nominate three
or more of the engineers listed to be appointed to act as
independent engineer (the "Independent Engineer") for the purposes
of this Agreement and the Generator shall appoint one of the
nominated engineers to act in that capacity. If EGAT does not
nominate three or more engineers or request a further list of
engineers within fifteen (15) days of receiving a list of engineers
from the Generator, EGAT shall be deemed to have nominated all of
the engineers on the list most recently provided to it by the
Generator. Except as otherwise provided in this Agreement, the
Generator shall bear all costs and expenses associated with the
Independent Engineer.
2.3.2 Starting fifteen (15) days after the end of the first full calendar
month after the Execution Date, and thereafter within fifteen (15)
days after the close of each calendar quarter up to the start of
construction of the Facility, the Generator shall submit for review
to EGAT quarterly progress reports substantially in the form set
out in Schedule 16.
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2.3.3 On the tenth (10th) Business Day of every month after the start of
construction of the Facility until the Commercial Operation Date of
the Second Unit, the Generator shall submit for review to EGAT
monthly progress reports substantially in the form set out in
Schedule 17.
2.3.4 The Generator shall provide EGAT with any clarifications or further
information which EGAT reasonably requests relating to the progress
of construction of the Facility or the Generator's ability to
perform its obligations to meet the Scheduled Commercial Operation
Dates.
2.3.5 Within a reasonable period after the Commercial Operation Date of
each Unit, the Generator shall provide to EGAT (i) a certificate
from the Independent Engineer confirming that the Facility has been
constructed in accordance with Prudent Utility Practices and the
provisions of Schedules 1, 7, 8, 10, 13 and 18, and (ii) a report
from the Independent Engineer on the status of the Facility in
relation to compliance with the material technical provisions of
the EPC Contract. The Generator shall provide any further
documentation or evidence supporting the Independent Engineer's
certificate which EGAT reasonably requests.
2.4 METERING
2.4.1 The Generator shall install, own and maintain, at the Generator's
expense, all Metering Equipment and associated transformers. The
Metering Equipment shall have the specifications set out in
Schedule 13.
The Generator, at its expense, shall provide (i) all metering
structures, unless otherwise agreed, and (ii) surge protection and
the necessary primary switches to isolate the metering
installation. The specifications of such structures and switches
shall be subject to EGAT's approval which shall not unreasonably be
withheld or delayed.
2.4.2 The Metering Equipment shall be sealed in the presence of both EGAT
and the Generator and the seals shall only be broken in the
presence of both Parties for inspection, testing or adjustment.
EGAT, at its expense, shall be entitled to have an authorized
representative present to monitor any test of the Metering
Equipment.
2.4.3 The accuracy of the Metering Equipment shall be tested annually as
specified in Schedule 13 by the Generator at the Generator's
expense, and the Generator shall give EGAT at least fourteen (14)
days' prior written notice of the date of such annual test.
Either Party may request additional tests of the accuracy of the
Metering Equipment in writing at least fourteen (14) days prior to
the proposed date of testing. The Generator shall bear the costs of
any such additional tests, except that EGAT shall bear such costs
if (i) EGAT requested the additional test, and (ii) the test
demonstrates that the Metering Equipment is performing within the
relevant tolerance limits as specified in Schedule 13.
Whenever any Metering Equipment is found to be defective or not
performing within such tolerance limits, it shall be adjusted,
repaired, replaced, or re-calibrated by the Generator at its
expense.
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2.4.4 If any of the Metering Equipment fails to register, or if the
Metering Equipment is found upon testing to be inaccurate by more
than plus or minus five tenths of one percent (plus or minus 0.5%)
in measuring Net Electrical Generation delivered, an adjustment
shall be made correcting all measurements by the inaccurate or
defective metering device for billing purposes, for both the amount
of the inaccuracy and the period of the inaccuracy, in the
following manner:
(a) If the Parties cannot agree on the amount of the adjustment
necessary to correct the measurements made by the Primary
Metering Equipment, the Parties shall use the Back-Up Metering
Equipment to determine the amount of such adjustment, provided
that the Back-Up Metering Equipment is operating within the
relevant tolerance limits as specified in Schedule 13. If the
Back-Up Metering Equipment is found upon testing to be
inaccurate by more than plus or minus five tenths of one
percent (plus or minus 0.5%) in measuring Net Electrical
Generation, and the Parties cannot agree on the amount of the
adjustment necessary to correct the measurements made by the
Back-Up Metering Equipment, the Parties shall, as soon as
practicable on the basis of procedures to be mutually agreed
upon by the Parties (which may be based upon deliveries of Net
Electrical Generation), estimate the amount of the necessary
adjustment on the basis of deliveries of the Net Electrical
Generation to the EGAT System during periods of similar
operating conditions when the Primary Metering Equipment was
registering accurately and taking into account the Facility's
Fuel use records during such periods;
(b) If the Parties cannot agree on the period during which the
inaccurate measurements were made, the period during which the
measurements are to be adjusted shall be the shorter of (i) one
half of the period from the last test of the Metering
Equipment, and (ii) the one hundred and eighty (180) days
immediately preceding the test that found the Metering
Equipment to be defective or inaccurate; and
(c) To the extent that the adjustment period covers a period of
deliveries for which payment has already been made by EGAT, the
Generator shall use the corrected measurements as determined in
accordance with this Section 2.4.4 to re-compute the amount due
for the period of the inaccuracy and shall subtract the
previous payments by EGAT for such period from such re-computed
amount. If the difference is a positive number, such difference
shall be paid by EGAT to the Generator; and if the difference
is a negative number, such difference shall be paid by the
Generator to EGAT. Payment of such difference shall be made by
means of a credit or an additional charge on the next statement
rendered pursuant to Section 19.
2.5 GRID CODE EQUIPMENT AND COMMUNICATION REQUIREMENTS
2.5.1 The Generator shall install, maintain and operate the
instrumentation set out in the applicable provisions of the Grid
Code relating to metering. The Generator shall also provide
telemetering equipment to facilitate remote monitoring of the
measurements and indications of such instrumentation.
2.5.2 All installation, maintenance, lease, service or purchase costs for
communications and remote indication units at the Facility required
by the Grid
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Code or specified in Schedules 10 and 13 shall be paid by the
Generator. The costs of communications between the Facility and
EGAT shall be borne by the Generator unless initiated by EGAT.
2.6 RIGHTS-OF-WAY AND EASEMENTS
2.6.1 No later than thirty (30) days after the Execution Date, the
Generator shall identify to EGAT (i) the location of the takeoff
structure at the Site and (ii) the location of the takeoff
structure at the substation on the New Main Transmission Line to
which the New Transmission Facilities shall be connected.
2.6.2 The Generator and EGAT shall cooperate in acquiring all ownership
rights, rights-of-way, easements and continuing access rights
(collectively, the ACCESS RIGHTS) necessary for the construction,
operation, maintenance, upgrading, replacement and removal of any
part of the New Transmission Facilities that will be located on
property owned by any Person other than the Generator.
2.6.3 In accordance with Section 2.6.2, if the Generator reasonably
believes it will be unable to acquire all of the Access Rights and
so notifies EGAT, EGAT shall endeavor to acquire the Access Rights
through the exercise of its authority under the EGAT Act as set out
in Paragraph 5 of Schedule 10. All costs and expenses incurred by
EGAT in the acquisition of the Access Rights shall be reimbursed by
the Generator in accordance with the Paragraph 5(f) of Schedule 10.
2.6.4 EGAT's obligations under Sections 2.6.2 and 2.6.3 shall not be
construed to require EGAT to exercise its authority under the EGAT
Act in a manner that would be extraordinary in light of EGAT's
historical use of such authority. For purposes of Section 14.1.1,
circumstances which would allow EGAT to acquire the Access Rights
only through such an extraordinary exercise of authority under the
EGAT Act shall be deemed beyond EGAT's reasonable control.
2.6.5 If all of the Access Rights have not been procured by 31 March
1998, each of the dates set out in Section 10.4 and each of the
milestone dates set out in Section 11 shall be extended by the
number of additional days required to complete acquisition of the
Access Rights. The Generator may elect to waive all or part of such
extension by giving EGAT, no later than twelve (12) months before
the Scheduled Commercial Operation Date for the First Unit, written
notice of the number of days of the extension that will not be
taken.
2.6.6 Notwithstanding EGAT's obligations under Section 2.6.2 and 2.6.3,
(i) the Generator shall bear all costs and expenses caused by any
delay in obtaining the Access Rights, (ii) any Events of Force
Majeure that delay or prevent acquisition of the Access Rights
shall be deemed to be Force Majeure affecting the Generator and
under no circumstances construed as Force Majeure affecting EGAT.
2.6.7 The Access Rights shall be acquired in EGAT's name or become EGAT's
by Law. EGAT shall allow the Generator, as EGAT's agent, to
exercise all uses of the Access Rights that are required for the
Generator's design, engineering, construction, testing, and
commissioning of the New Transmission Facilities.
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2.6.8 The Generator shall grant to EGAT all necessary rights-of-way and
easements, including adequate and continuing access rights to the
Generator's property, to install, operate, maintain, replace, or
remove any of EGAT's equipment or facilities for the Connection.
Such rights-of-way and easements shall be granted no later than the
date construction of the New Transmission Facilities is completed
and shall survive the termination or expiration of this Agreement
for a period of at least one hundred and eighty (180) days to
enable EGAT to remove any of its equipment or facilities located
thereon.
2.7 PROVISION OF INFORMATION AND CONSULTATION RELATING TO EGAT TRANSMISSION
FACILITIES
2.7.1 EGAT has provided the Generator with the materials EGAT provides
contractors or suppliers of equipment on their appointment by EGAT
to construct transmission facilities or supply equipment for that
purpose. Such materials are included or identified in Schedule 10
and set out EGAT's standard design specifications and engineering
and construction guidelines, standard contractual terms, conditions
and warranties required from contractors, and other standard
practices relating to the construction of EGAT transmission
facilities. EGAT shall provide any such additional materials
reasonably requested by the Generator.
2.7.2 EGAT shall afford the Generator reasonable opportunities for
consultation concerning the materials provided pursuant to Section
2.7.1.
2.8 COMPLETION OF NEW TRANSMISSION FACILITIES
2.8.1 The Generator shall design, engineer, construct, test, and
commission the New Transmission Facilities in accordance with (i)
the standard EGAT practices and contractual requirements as set out
in the materials and information provided to the Generator under
Sections 2.7.1 and 2.7.2, and (ii) Prudent Utility Practices
whenever there is not an applicable standard EGAT practice or
contractual requirement. Although EGAT shall by Law and the
provisions of Section 2.6 and this Section 2.8.1 have legal title
to the New Transmission Facilities from the start of their
construction, the Generator shall bear the risk of loss of or
damage to the New Transmission Facilities until the NTF
Commissioning Completion Date.
2.8.2 Unless otherwise agreed between the Parties, all contractors and
suppliers of equipment appointed by the Generator for the design,
engineering, construction, testing or commissioning of the New
Transmission Facilities shall be contractors or suppliers of
equipment that have previously performed similar services for or
supplied similar equipment to EGAT. The Generator shall consult
with EGAT concerning the selection of contractors and suppliers of
equipment, and EGAT shall identify for the Generator contractors or
suppliers of equipment that have previously performed services or
supplied equipment to EGAT's satisfaction.
2.8.3 On the tenth (10th) Business Day of every month after the start of
construction of the New Transmission Facilities, the Generator
shall submit for EGAT's review monthly progress reports on the
construction of the New Transmission Facilities substantially in
the form set out in Schedule 17.
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2.8.4 The Generator shall allow representatives of EGAT to inspect all
construction sites of the New Transmission Facilities at any
reasonable time during their construction or commissioning,
provided that EGAT shall notify the Generator in writing reasonably
in advance of any such inspection and shall cooperate with the
Generator to minimize interference with the Generator's contractors
at such sites. EGAT, at its expense, shall be entitled to attend
and monitor the inspection, testing, energizing and commissioning
of the New Transmission Facilities pursuant to Sections 2.8, 2.9
and 2.10 and Schedule 18.
2.8.5 If at any point during the construction or commissioning of the New
Transmission Facilities EGAT determines that modifications in the
New Transmission Facilities should be made to correct any
discrepancies between the Generator's construction of the New
Transmission Facilities and the materials and information provided
by EGAT to the Generator in accordance with Section 2.7, the
Generator shall make any such modifications reasonably proposed by
EGAT. The Generator shall bear the cost of any such modifications
that are required.
2.8.6 When the New Transmission Facilities are ready for initial
inspection and testing, the Generator shall so notify EGAT in a
statement in a form reasonably acceptable to EGAT. The initial
inspection and testing of the NTF Connection Point and the New
Transmission Facilities shall be scheduled for a date agreed by the
Parties which shall be not more than seven (7) days after EGAT's
receipt of such statement.
2.8.7 On the date determined pursuant to Section 2.8.6, the Generator
shall carry out the initial inspection and testing of the NTF
Connection Point and the New Transmission Facilities in accordance
with Paragraph 3.1 of Part A of Schedule 18.
2.8.8 EGAT shall review on-site the results of the initial inspection and
testing of the NTF Connection Point and the New Transmission
Facilities carried out pursuant to Section 2.8.7. After receiving
the results of such inspection and tests, EGAT shall either (i)
within one (1) day provide the Generator with written notice that
the inspection and testing requirements set out in Paragraph 3.1 of
Part A of Schedule 18 have been met, or (ii) within seven (7) days
provide the Generator with a written report describing any areas
where, in EGAT's reasonable opinion, such requirements have not
been met.
2.8.9 If pursuant to Section 2.8.8(ii) EGAT reports that the New
Transmission Facilities or the NTF Connection Point is not ready
for energizing, the Generator shall determine and remedy the cause
of such failure. The remedy and cost of the remedy shall be borne
by the Generator. The Generator shall notify EGAT when further
inspection and testing pursuant to Paragraph 3.1 of Part A of
Schedule 18 can take place. Such further inspection and testing
shall commence on a date agreed by the Parties which shall be not
more than seven (7) days after the Generator so notifies EGAT. Such
further inspection and testing and EGAT's review of the results
thereof shall proceed pursuant to Sections 2.8.6 to 2.8.8 and this
Section.
2.8.10 EGAT shall provide the energizing source and the Generator shall
energize the NTF Connection Point on an agreed date occurring not
more than five (5) days after EGAT issues to the Generator written
notice pursuant to Section 2.8.8(i),
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provided that EGAT shall not be required to energize the NTF
Connection Point before the Scheduled NTF Energizing Date. The EGAT
energizing source shall be at least one (1) energized 500kV circuit
from the New Main Transmission Line. After the Generator has
energized the NTF Connection Point, the Generator shall conduct
final energizing and commissioning tests in accordance with
Paragraphs 3.2 and 3.3 of Part A of Schedule 18.
2.8.11 EGAT shall review on-site the results of the final energizing and
commissioning tests of the NTF Connection Point and the New
Transmission Facilities carried out pursuant to Section 2.8.10.
After receiving the results of such tests, EGAT shall either (i)
within one (1) day provide the Generator with written notice that
the test requirements set out in Paragraphs 3.2 and 3.3 of Part A
of Schedule 18 have been met with respect to all tests that can be
performed using all New Main Transmission Line circuits available
at the time for energizing the NTF Connection Point and New
Transmission Facilities, or (ii) within seven (7) days provide the
Generator with a written report describing any areas where, in
EGAT's reasonable opinion, such requirements have not been met.
2.8.12 EGAT shall review on-site the results of the final energizing and
commissioning tests of the 500kV circuits from NTF Connection Point
to the Connection Point carried out pursuant to Section 2.8.10.
After receiving the results of such tests, (i) within one (1) day
EGAT shall provide the Generator with written notice of any
determination by EGAT that the test requirements set out in
Paragraphs 3.2 and 3.3 of Part A of Schedule 18 have been met with
respect to one or both such circuits, and (ii) if EGAT determines
that either of such 500kV circuits have not met such requirements,
within seven (7) days EGAT shall provide the Generator with a
written report describing any areas where, in EGAT's reasonable
opinion, such requirements have not been met.
2.8.13 If EGAT reports that the New Transmission Facilities or the NTF
Connection Point have not met the requirements for notice pursuant
to Section 2.8.11(i) or that either of the 500kV circuits from the
NTF Connection Point to the Connection Point has not met the
requirements for notice pursuant to Section 2.8.12(i), the
Generator shall determine and remedy the cause of such failure. The
remedy and cost of the remedy shall be borne by the Generator. The
Generator shall notify EGAT when further testing pursuant to
Paragraphs 3.2 and 3.3 of Part A of Schedule 18 can take place.
Such further testing shall commence on a date agreed by the Parties
which shall be not more than seven (7) days after the Generator so
notifies EGAT. Such further testing and EGAT's review of the
results thereof shall proceed pursuant to Sections 2.8.10 to 2.8.12
and this Section.
2.8.14 The NTF Commissioning Completion Date shall be the date which is
the later of (i) the date EGAT provides the Generator with notice
pursuant to Section 2.8.11(i), or (ii) the date EGAT provides
notice pursuant to Section 2.8.12(i) that both of the 500kV
circuits from the NTF Connection Point to the Connection Point have
met the test requirements set out in Paragraphs 3.2 and 3.3 of Part
A of Schedule 18.
2.8.15 Beginning on the NTF Commissioning Completion Date, EGAT shall (i)
assume the risk of loss of or damage to the New Transmission
Facilities, and (ii) operate, maintain and energize the New
Transmission Facilities in accordance with Prudent Utility
Practices. Within thirty (30) days after the NTF
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Commissioning Completion Date, the Generator shall assign to EGAT,
with effect from the NTF Commissioning Completion Date, all
continuing contractual rights and warranties the Generator has
under all contracts relating to the construction of the New
Transmission Facilities and equipment procured for that purpose.
Such contractual rights and warranties shall meet or exceed the
requirements set out in Paragraph 6 of Schedule 10.
2.8.16 There shall be included as a separate component of the Availability
Payments an amount (the ADDED FACILITY CHARGE) to reimburse the
Generator for costs incurred by it (including amounts paid by it to
EGAT pursuant to Section 2.6 and Paragraph 5(f) of Schedule 10) in
connection with the acquisition or transfer of Access Rights and in
the design, engineering, construction, testing and commissioning of
the New Transmission Facilities. The Added Facility Charge shall be
a monthly payment payable for 150 consecutive months equal to the
amounts specified in Paragraph 6.2 of Schedule 2. EGAT shall
commence payments of the Added Facility Charge as part of the first
payment of Availability Payments (after the Commercial Operation
Date of the First Unit or pursuant to Section 2.10.4 or 14.4.2).
Thereafter, EGAT shall pay the Added Facility Charge to the
Generator irrespective of whether EGAT's obligation to make
Availability Payments is otherwise excused in whole or in part
during the Term.
2.9 INSPECTION AND ENERGIZING OF THE CONNECTION POINT AND FACILITY SWITCHYARD
2.9.1 When the Facility Switchyard is ready for the Connection Point to
be energized, the Generator shall so notify EGAT in a statement in
a form reasonably acceptable to EGAT. The inspection and testing of
the Connection Point and the Facility Switchyard shall be scheduled
for a date agreed by the Parties which shall be on or before the
later of (i) fourteen (14) days after EGAT's receipt of such
statement, and (ii) one day after EGAT provides notice pursuant to
Section 2.8.12(i) that the test requirements set out in Paragraphs
3.2 and 3.3 of Part A of Schedule 18 have been met with respect to
at least one of the two 500kV circuits from the NTF Connection
Point to the Connection Point.
2.9.2 On the date determined pursuant to Section 2.9.1, the Generator
shall carry out the initial inspection and testing of the
Connection Point and Facility Switchyard in accordance with
Paragraph 3.1 of Part B of Schedule 18. EGAT, at its expense, may
attend and monitor the inspection and testing of the Connection
Point and the Facility Switchyard.
2.9.3 EGAT shall review at the Site the results of the initial inspection
and testing of the Connection Point and the Facility Switchyard
carried out pursuant to Section 2.9.2. After receiving the results
of such inspection and testing, EGAT shall either (i) within one
(1) day provide the Generator with written notice that the test
requirements set out in Paragraph 3.1 of Part B of Schedule 18 have
been met, or (ii) within seven (7) days provide the Generator with
a written report describing any areas where, in EGAT's reasonable
opinion, such requirements have not been met.
2.9.4 If EGAT reports that the Facility Switchyard or the Connection
Point is not ready for energizing, the Generator shall, at its
expense, make such changes to the Facility Switchyard or the
Connection Point as are required and notify EGAT when further
inspection and testing pursuant to Paragraph 3.1 of Part B
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of Schedule 18 can take place. Such further inspection and testing
shall commence on a date agreed by the Parties which shall be not
more than seven (7) days after the Generator so notifies EGAT. Such
further testing and EGAT's review of the results thereof shall
proceed pursuant to Sections 2.9.2 and 2.9.3 and this Section.
2.9.5 EGAT shall provide the energizing source and the Generator shall
energize the Connection Point on an agreed date occurring not more
than five (5) days after EGAT issues to the Generator written
notice pursuant to Section 2.9.3(i), provided that EGAT shall not
be required to energize the NTF Connection Point for this purpose
before the Scheduled Energizing Date. The Generator shall conduct
final energizing and commissioning tests for the Connection Point
and Facility Switchyard pursuant to Paragraphs 3.2 to 3.4 of Part B
of Schedule 18.
2.9.6 EGAT shall review the final energizing and commissioning test
results of the Connection Point and the Facility Switchyard. After
receiving the results of such testing, EGAT shall either (i) within
one (1) day provide the Generator with written notice that the test
requirements set out in Paragraphs 3.2 to 3.4 of Part B of Schedule
18 have been met, or (ii) within seven (7) days provide the
Generator with a written report describing any areas where, in
EGAT's reasonable opinion, such requirements have not been met.
2.9.7 If EGAT reports that the Facility Switchyard or the Connection
Point have not met the requirements for notice pursuant to Section
2.9.6(i), the Generator shall determine and remedy the cause of
such failure. The remedy and cost of the remedy shall be borne by
the Generator. The Generator shall notify EGAT when further testing
pursuant to Paragraphs 3.2 to 3.4 of Part B of Schedule 18 can take
place. Such further testing shall commence on a date agreed by the
Parties which shall be not more than seven (7) days after the
Generator so notifies EGAT. Such further testing and EGAT's review
of the results thereof shall proceed pursuant to Sections 2.9.5 and
2.9.6 and this Section.
2.10 SYNCHRONIZING AND COMMERCIAL OPERATION
2.10.1 After EGAT provides notice pursuant to Section 2.9.6(i), the
Generator shall conduct the Unit synchronizing tests set out in
Paragraph 3.5 of Part B of Schedule 18.
EGAT shall review the results of such Unit synchronizing tests.
After receiving the results of such testing, EGAT shall either (i)
within one (1) day provide the Generator with written notice that
the test requirements set out in Paragraph 3.5 of Part B of
Schedule 18 have been met, or (ii) within seven (7) days provide
the Generator with a written report describing any areas where, in
EGAT's reasonable opinion, such requirements have not been met.
If EGAT reports that the Unit has not met the requirements for
notice pursuant to subclause (i) of this Section, the Generator
shall determine and remedy the cause of such failure. The remedy
and cost of the remedy shall be borne by the Generator. The
Generator shall notify EGAT when further testing pursuant to
Paragraph 3.5 of Part B of Schedule 18 can take place. Such further
testing shall commence on a date agreed by the Parties which shall
be not more than seven (7) days after the Generator so notifies
EGAT. Such further testing and EGAT's review of the results thereof
shall proceed pursuant to this Section.
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The Generator shall be allowed to synchronize on an agreed date
occurring after EGAT provides notice pursuant to subclause (i) of
this Section 2.10.1, but no more than one hundred and eighty (180)
days before the Commercial Operation Date of the Unit the Parties
anticipate to be set pursuant to Section 2.10.2.
2.10.2 On the date which is twelve (12) months before the Scheduled
Commercial Operation Date of the First Unit, EGAT shall provide the
Generator with written notice stating whether the reserve capacity
in the EGAT System forecasted for the Scheduled Commercial
Operation Date of the First Unit is greater than or less than
fifteen percent (15%).
If such forecasted reserve capacity is less than fifteen percent
(15%), the Commercial Operation Date of the First Unit may occur on
or after its Earliest Commercial Operation Date and the Commercial
Operation Date of the Second Unit may occur on or after its
Earliest Commercial Operation Date. If such forecasted reserve
capacity is greater than fifteen percent (15%), the Commercial
Operation Date of the Units may not occur before their respective
Scheduled Commercial Operation Dates without the written consent of
EGAT which shall be at EGAT's sole discretion.
Subject to the foregoing, the Commercial Operation Date of each
Unit shall be a date agreed by EGAT and the Generator occurring no
more than five (5) days after the later of (i) EGAT's receipt of a
certificate of the Independent Engineer certifying that the Unit
has successfully completed the Commercial Operations Test in
accordance with Schedule 14, and (ii) the NTF Commissioning
Completion Date.
2.10.3 If the Commercial Operation Date for either Unit fails to occur by
its Scheduled Commercial Operation Date, the Generator shall pay
EGAT liquidated damages of four (4) Baht/kW per day of Contracted
Capacity of such Unit for the number of days such failure is not
due to the actions or omissions of EGAT or otherwise excused
hereunder in the period from the Unit's Scheduled Commercial
Operation Date to the earlier of (i) its Commercial Operation Date,
or (ii) the date two hundred and forty (240) days after the
Scheduled Commercial Operation Date.
2.10.4 If the Commercial Operation Date of either Unit fails to occur by
its Scheduled Commercial Operation Date, EGAT shall make
Availability Payments to the Generator with respect to that Unit
for the number of days during the period from its Scheduled
Commercial Operation Date to its Commercial Operation Date that
such failure is due solely to EGAT's not completing the New Main
Transmission Line or not energizing the NTF Connection Point by the
Scheduled NTF Energizing Date or not energizing the Connection
Point by the Scheduled Energizing Date, unless such failure is
otherwise excused hereunder. EGAT shall commence making such
Availability Payments on the Scheduled Commercial Operation Date of
the Unit after such date is adjusted as described below.
For the purposes of determining the date such Availability Payments
shall commence, the Scheduled Commercial Operation Date of the Unit
(i) shall be extended by one day for each day by which the
occurrence of the Commercial Operation Date is delayed due to
causes attributable to the Generator, but (ii) shall not be
extended pursuant to Section 10.5.2 for delay due solely to EGAT's
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not completing the New Main Transmission Line, not energizing the
NTF Connection Point by the Scheduled NTF Energizing Date or not
energizing the Connection Point by the Scheduled Energizing Date.
EGAT shall continue making such Availability Payments until the
earlier of (i) the date upon which EGAT has made such Availability
Payments for the same number of days as the Unit's Commercial
Operation Date was delayed by EGAT as determined in accordance with
the preceding paragraph, (ii) the Commercial Operation Date of the
Unit, or (iii) the termination of this Agreement.
Any Availability Payments made by EGAT in accordance with this
Section 2.10.4 shall be calculated using the Contracted Capacity of
the Unit. Costs which the Generator either did not incur or were
avoidable because the Unit was not Available shall be deducted from
such Availability Payments, and any additional costs necessarily or
reasonably incurred as a result of the delay caused by EGAT shall
be added to such Availability Payments.
If the Dependable Contracted Capacity that is established for
either Unit on its Commercial Operation Date is less than its
Contracted Capacity, then the Availability Payments paid to the
Generator with respect to that Unit during the period between its
Scheduled Commercial Operation Date and its Commercial Operation
Date shall be recalculated using its Dependable Contracted Capacity
on its Commercial Operation Date. If the Availability Payments made
in respect of that period exceed the amount reached by the
recalculation, EGAT shall be entitled to deduct an amount equal to
the excess from future payments due to the Generator by EGAT
together with interest on the amount of the excess at the Overdraft
Rate. Such deductions shall be made from such future payments pro-
rata over the same period of time in which the excess Availability
Payments were made.
2.10.5 Any Availability Payments payable by EGAT to the Generator in
accordance with Section 2.10.4 shall be paid in accordance with
Section 19.2. Liquidated damages payable by the Generator to EGAT
in accordance with Section 2.10.3 shall be drawn by EGAT from any
portion of the Development Security remaining after any reduction
thereof in accordance with Section 13.2. To the extent such portion
of the Development Security is insufficient to compensate EGAT for
all liquidated damages due under Section 2.10.3, the Generator
shall pay EGAT any further liquidated damages in accordance with
Section 19.2.
2.11 TESTING
2.11.1 Prior to the Commercial Operation Date of each Unit, the Generator
shall conduct the Commercial Operations Test for the Unit. Such
test will (i) determine the Unit's Dependable Contracted Capacity,
and (ii) verify the Unit's Contracted Operating Characteristics.
The Generator shall provide thirty (30) days' prior written notice
to EGAT of such test of each Unit. After such notice has been
given, the Generator shall provide at least seven (7) days' prior
written notice to EGAT of any rescheduling of the date of such
test. EGAT, at its expense, may attend and monitor the Commercial
Operations Test of each Unit.
The Generator shall bear the costs and expenses of the Commercial
Operations Tests and all other tests conducted before the
Commercial Operation Date.
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2.11.2 After the Commercial Operation Date of each Unit, the Unit shall be
tested semi-annually during each Contract Year (and after each time
the Unit is withdrawn from service for a major overhaul,
modification or renovation) to establish the Dependable Contracted
Capacity. The Dependable Contracted Capacity so established (i) may
be more or less than the previously established Dependable
Contracted Capacity for the Unit, but (ii) may not exceed the
Unit's Contracted Capacity. The Generator shall bear the costs and
expenses of all such semi-annual tests, and EGAT shall bear the
costs and expenses of attending and monitoring such tests.
2.11.3 EGAT shall have the right to require the Generator to conduct a Net
Capacity Test for either Unit upon seven (7) days' prior written
notice to the Generator if EGAT reasonably believes that the
generating capacity of the Unit is less than the Dependable
Contracted Capacity then in effect for the Unit for any reason
whatsoever except (i) Governmental Force Majeure, (ii) a condition
caused by the EGAT System (including Force Majeure affecting EGAT),
or (iii) a Planned Outage. The Generator shall bear the costs and
expenses of any test required by EGAT under this Section 2.11.3,
but EGAT shall repay the Generator such costs and expenses if the
Net Capacity Test demonstrates a Dependable Contracted Capacity
equal to or greater than that in effect for the Unit when EGAT
requested the Net Capacity Test. In either case, EGAT shall be
responsible for any costs and expenses of attending and monitoring
such tests.
2.11.4 The Generator shall have the right to conduct Net Capacity Tests to
establish a new Dependable Contracted Capacity for either Unit upon
seven (7) days' prior written notice to EGAT. The Generator may
request such determinations of Dependable Contracted Capacity on no
more than four (4) occasions in any Contract Year, exclusive of any
such determinations requested by EGAT pursuant to Section 2.11.3.
The Generator shall bear the costs and expenses of any test
required under this Section 2.11.4, and any expenses incurred by
EGAT in attending and monitoring such tests.
2.11.5 The Dependable Contracted Capacity of each Unit on its Commercial
Operation Date shall be the Dependable Contracted Capacity
established by the most recently conducted Net Capacity Test of the
Unit. The Dependable Contracted Capacity so established may not
exceed the Unit's Contracted Capacity. The Dependable Contracted
Capacity established for a Unit in the most recently conducted Net
Capacity Test shall be effective until the Dependable Contracted
Capacity for that Unit is next determined in accordance with this
Section 2.11 and Schedule 14. Any Availability Notice issued by the
Generator to EGAT pursuant to Section 5 shall not declare
Availability for a Unit in excess of the Dependable Contracted
Capacity in effect for that Unit at the time any such Availability
Notice is issued, except as permitted in Paragraph 17 of Schedule
2.
2.12 REVIEW BY EGAT
Notwithstanding any other provisions of this Agreement, any review by EGAT
of any materials, documents, designs, drawings, schedules, design data or
other information submitted by the Generator concerning the Facility under
this Agreement or prior to the execution of this Agreement, or any consent
by EGAT under Section 2.2.3 to any modification in the Facility's
construction, or any inspection or testing of the Facility by EGAT, or any
presence of EGAT to witness any test performed by the Generator, whether
undertaken pursuant to this Agreement or not, shall not be deemed to
constitute
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<PAGE>
an endorsement of the Facility nor a warranty or other assurance by EGAT of
the safety, durability or reliability of the Facility, nor release the
Generator of any of its obligations under this Agreement.
3. PROVISION AND PURCHASE OF AVAILABILITY AND ELECTRICITY
3.1 OBLIGATION TO PROVIDE DEPENDABLE CONTRACTED CAPACITY AND CONTRACTED
OPERATING CHARACTERISTICS
3.1.1 In consideration of EGAT's agreement to pay Availability Payments,
Energy Payments and other sums to the Generator on the terms and
conditions of this Agreement, the Generator shall throughout the
Term maintain, repair, fuel and operate the Facility as required by
Prudent Utility Practices, the Grid Code and all applicable Laws to
ensure the provision of the Dependable Contracted Capacity and the
Contracted Operating Characteristics.
3.1.2 The Generator shall ensure that it does not at any time issue or
allow to remain outstanding, with respect to a Unit, a declaration
of revised Operating Characteristics which declares the
Availability and Operating Characteristics of the Unit at levels or
values different from those that the Unit could achieve at the
relevant time except:
(a) during periods of Planned Outage or otherwise with the
consent of EGAT;
(b) while repairing or maintaining the Facility or equipment
necessary to the operation of the Facility where such repair or
maintenance cannot reasonably, in accordance with Prudent
Utility Practices, be deferred to a period of Planned Outage;
(c) where necessary to avoid an imminent risk of injury to persons
or material damage to property (including the Facility);
(d) if it is not lawful for the Generator to operate the Facility;
or
(e) to the extent that the Generator is affected by a Force
Majeure;
provided that this Section shall not require the Generator to
declare Availability or Operating Characteristics exceeding the
requirements specified in Schedule 1.
3.1.3 EGAT shall accept test energy generated from a Unit prior to its
Commercial Operation Date and pay the Generator for such energy as
measured by Metering Equipment at the Metering Point in accordance
with Section 19 an amount equal to the sum of:
(a) the cost of Fuel used by the Generator to generate such test
energy; plus
(b) the variable operation and maintenance costs reasonably
incurred by the Generator in producing such test energy.
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<PAGE>
3.2 COMPLIANCE WITH THE GRID CODE
3.2.1 The Generator shall comply with the provisions of the Grid Code in
effect throughout the Term, subject to any variations therefrom
granted to the Generator by EGAT.
3.2.2 EGAT shall use its reasonable efforts to notify the Generator in
advance of proposed changes to the Grid Code, and the Generator may
provide comments to EGAT in regard to such proposed changes. EGAT
shall give due consideration to any such comment.
3.2.3 Within the period of time stated in the notice (which shall
generally not be less than thirty (30) days) after receipt of a
notice of change in the Grid Code which does not require Facility
modifications, or which does not adversely affect the Facility's
operation, the Generator shall comply with such change to the Grid
Code. If Facility modifications are required or the Facility's
operation would be adversely affected by a change in the Grid Code,
the Generator shall as soon as practicable advise EGAT of the
anticipated length of time required in order for the Generator,
acting diligently, to effect compliance with such notice. The
Generator shall take immediate steps to comply with such notice
(unless EGAT subsequently notifies the Generator in writing that
the Generator may discontinue such compliance).
3.2.4 If changes to the Grid Code result in increases or decreases in
costs or revenues to the Generator, the provisions of Sections
3.2.5 and 17 shall apply and EGAT shall continue to make
Availability Payments to the Generator in accordance with Schedule
2 without deductions due to the Grid Code's effect on the
Facility's operations during the time period required for the
Generator to adjust the Facility or its operation to comply with
any such changes to the Grid Code.
3.2.5 The Generator shall provide EGAT with prompt written notice
describing in reasonable detail any circumstances in which actions
the Generator is required to take to comply with a change in the
Grid Code will prevent the Generator from performing other
obligations under this Agreement. The Generator's inability to
perform such other obligations in such circumstances shall not in
and of itself be a breach of this Agreement.
3.3 SALE AND PURCHASE OF ELECTRICITY
3.3.1 The Generator shall deliver to the Connection Point and sell to
EGAT, and EGAT shall purchase from the Generator, on the terms and
conditions of this Agreement, the Net Electrical Generation. The
Net Electrical Generation delivered to EGAT shall be measured at
the Metering Point using the Primary Metering Equipment. If the
Primary Metering Equipment is inaccurate, otherwise defective, or
being tested pursuant to Section 2.4, the measurements recorded by
the Back-Up Metering Equipment shall be used to measure the Net
Electrical Generation.
3.3.2 The Generator shall not deliver any electricity generated by the
Facility to any third party during the Term or any extension of the
Term made in accordance with this Agreement.
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3.4 PROVISION OF STANDBY SERVICE
To the extent permitted by law, EGAT shall offer the Generator standby
electrical service at the applicable standby rate.
3.5 DISPATCH INSTRUCTIONS
The Generator shall operate the Facility as a fully dispatchable facility.
Subject to the terms and conditions of this Agreement, EGAT shall have the
sole right and discretion to schedule and Dispatch the generation of
electricity from the Facility and the delivery thereof into the EGAT
System, provided that EGAT shall Dispatch the Facility in a manner that is
consistent with:
(a) the principle of merit order Dispatch, subject to the needs of the
EGAT System;
(b) the Grid Code;
(c) Prudent Utility Practices; and
(d) all applicable Laws, regulations and permits.
Except in Emergency Conditions, EGAT shall only issue Dispatch Instructions
that are in accordance with the Generator's declared Availability and
Declared Operating Characteristics of each Unit as notified by the
Generator from time to time. The Generator may but shall not be obliged to
comply with any Dispatch Instruction that would require the Generator to
operate either Unit beyond its declared Availability or Declared Operating
Characteristics at the relevant time unless such Dispatch Instruction is
stated to be issued under Emergency Conditions. In Emergency Conditions
the Generator shall not be required to operate either Unit beyond its
Design Limits or in any manner that would be inconsistent with Prudent
Utility Practices.
3.6 OPERATION AND MAINTENANCE (O&M) REPORTS
At least once in each calendar quarter, the Generator shall submit to EGAT
a report from the O&M operator containing the information set out in
Schedule 22. For so long as the Financing Documents remain effective, EGAT
shall be provided with complete copies of all O&M reports provided to
Financing Parties by the Generator or the O&M operator.
4. DELIVERY OF ELECTRICITY
4.1 QUALITY OF SUPPLY
If at any time the supply of electricity from a Unit does not comply as to
its electrical characteristics with the applicable requirements of the Grid
Code or this Agreement as a result of the breach by the Generator of any
such requirements:
(a) the Generator shall take the steps necessary pursuant to Prudent
Utility Practices to remedy such non-compliance as soon as possible;
and
(b) the Unit shall be deemed to be not Available to the extent of such non-
compliance.
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<PAGE>
4.2 TITLE AND RISK OF LOSS
Title to and risk of loss of any electricity generated by the Facility and
delivered to EGAT in accordance with this Agreement shall pass to EGAT at
the Connection Point.
EGAT shall bear the cost of transmission losses incurred on the EGAT side
of the Metering Point in the transmission of electricity sold to EGAT,
except as attributable to diversion or theft before the Connection Point.
4.3 FAILURE OF THE SYSTEM
The calculation of Availability Payments under Schedule 2 shall not include
any deductions for:
(a) any failure, restriction or outage of transmission facilities on the
EGAT side of the Connection Point;
(b) any action which the Generator, in accordance with the Grid Code, is
obliged or entitled to take due to any frequency excursion on the EGAT
System outside the frequency ranges and time limitations set out in
Paragraph 4.1 of Schedule 1; or
(c) any shedding of the Net Electrical Generation of a Unit instructed by
EGAT.
5. AVAILABILITY PAYMENTS
5.1 CALCULATION OF AVAILABILITY PAYMENTS
Commencing from the Commercial Operation Date of the First Unit, the
Generator shall be entitled to receive from EGAT Availability Payments
calculated in accordance with the provisions of Schedule 2.
5.2 CONFIRMATION AND PAYMENT OF AVAILABILITY PAYMENTS
The Actual Availability and the Operating Characteristics of the Units in
each Settlement Period shall be confirmed in a Final Confirmation Statement
issued in accordance with Section 18. Amounts calculated pursuant to
Schedule 2 shall be payable in accordance with Section 19.
5.3 NOTICES OF AVAILABILITY AND DECLARED OPERATING CHARACTERISTICS
5.3.1 The Generator shall keep EGAT advised of the Availability and
Operating Characteristics of the Units by issuing Availability
Notices and Outage Notices in accordance with the Grid Code.
5.3.2 Any Availability Notice or Outage Notice may be given by telephone
in accordance with the Grid Code. The Notice shall be confirmed by
facsimile as soon as possible thereafter and in any event shall be
sent to EGAT within two hours. Where a facsimile is so sent by way
of confirmation it shall state clearly that it is in confirmation
of a Notice already given by telephone and must state the exact
time at which the Notice was given by telephone.
5.3.3 If, following the occurrence of an event of the type specified in
Paragraph 3.4 of Schedule 2, EGAT wishes to issue a Post Event
Notice, it shall deliver a copy of the Post Event Notice to the
Generator as soon as reasonably practicable but not
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later than 5 p.m. on the fifth (5th) Business Day after the day on
which the relevant event occurred.
5.3.4 A Post Event Notice shall specify:
(a) the Settlement Period during which the relevant event occurred;
and
(b) the matters or values which EGAT intends to re-declare as a
result of the relevant event.
5.3.5 If the Generator considers that a Post Event Notice was not validly
issued in accordance with this Agreement, it shall notify EGAT,
within seventy-two (72) hours after receipt of the written Post
Event Notice or confirmation thereof, of the grounds for its
objection. If EGAT and the Generator are unable to resolve the
Generator's objection within fourteen (14) days of the date of such
objection, the matter shall be referred to an Expert for
determination in accordance with Section 15. If the Generator does
not notify EGAT of its objection within such seventy-two (72) hour
period, the Post Event Notice shall be deemed accepted by the
Generator.
6. ENERGY PAYMENTS
6.1 ENTITLEMENT TO AND CALCULATION OF ENERGY PAYMENTS
Commencing on the Commercial Operation Date of the First Unit, the
Generator shall be entitled to receive from EGAT, for each Settlement
Period, the Energy Payments for electrical energy generated from the
Facility in response to Dispatch Instructions as measured and calculated in
Schedule 3. The Generator shall not be entitled to receive an Energy
Payment calculated in accordance with Schedule 3 for either (i) operations
carried out without a Dispatch Instruction, or (ii) any operation or part
thereof requested by EGAT's Control Center but not carried out by the
Generator.
6.2 CONFIRMATION AND PAYMENT OF ENERGY PAYMENTS
The operations of the Facility in each Settlement Period shall be reflected
in a Final Confirmation Statement issued in accordance with Section 18.
The Energy Payments due to the Generator pursuant to this Section 6 shall
be payable in accordance with Section 19.1.
7. MINIMUM TAKE
If the Generator is required to take or transport a minimum quantity of
Fuel by the Fuel Purchase Agreement or the Fuel Transportation Agreement,
and provided that the terms of such agreements have been approved by EGAT
in accordance with Sections 9.1 and 9.2, EGAT shall share the costs (the
MINIMUM TAKE LIABILITY) incurred by the Generator after the Commercial
Operation Date of the Second Unit with respect to a failure to take or
transport the minimum quantity of Fuel, as calculated under the provisions
of the Fuel Purchase Agreement and Fuel Transportation Agreement.
EGAT shall not share the Minimum Take Liability if such a failure (i)
occurs before the Commercial Operation Date of the Second Unit, or (ii) is
due to any causes other than Dispatch Instructions by EGAT, Force Majeure
affecting EGAT or Governmental Force Majeure.
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The method of sharing shall be on the basis of the following formula:
<TABLE>
<S> <C>
EA - Expected Unit Availability
EA = CAH for each Contract Year/8760
For two units, EA = (CAH//1// + CAH//2//) / (8760 x 2)
AA - Actual Availability
AA = (Sigma)AAH/8760
(Sigma)AAH = Equivalent Achieved Available Hours for each Contract Year
For two units, AA = ((Sigma)AAH//1// + (Sigma)AAH//2//)/(8760 x 2)
ACF - Annual Capacity Factor
ACF = MWh generated during Contract Year
----------------------------------
Contracted Capacity (CC) x 8760
For two units, ACF = (ACF//1// + ACF//2//) /2
MACF - Minimum Annual Capacity Factor below which the Minimum Fuel
Purchase Obligation applies = 0.60
If ACF is greater than or equal to MACF, then Minimum Take Liability does not apply.
If ACF is less than MACF, the Minimum Take Liability applies, with the Generator's Share and
EGAT's Share given by the following:
EGAT's Share = 1 - EA - AA
-------
EA - MACF
Generator's Share = EA - AA
-------
EA - MACF
</TABLE>
The preceding formula allocates the Minimum Take Liability between EGAT and
the Generator within the following boundaries:
(a) If AA is greater than or equal to EA, EGAT shall bear one hundred
percent (100%) of the Minimum Take Liability, and
(b) If AA is less than or equal to the MACF, the Generator shall bear one
hundred percent (100%) of the Minimum Take Liability.
8. ENVIRONMENTAL QUALITY REQUIREMENTS
8.1 The Generator shall comply with or exceed the standards set out in
Schedule 8 and all applicable environmental Laws.
8.2 If, subsequent to the Execution Date, the Generator is required by a
Change-in-Law to meet environmental standards which are more stringent than
those set out in Schedule 8,
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the Generator may submit to EGAT a certificate setting out the details of
increased costs resulting from such change, in accordance with the
provisions of Section 17. Such a certificate shall include or be
accompanied by sufficient technical, environmental, and financial
information and data to demonstrate that the least-cost option consistent
with Prudent Utility Practices to meet or exceed the environmental Law has
been selected. EGAT and the Generator shall promptly determine, in good
faith, any necessary adjustments in accordance with Section 17.
8.3 The Generator shall establish environmental management systems and
facilities to ensure that the applicable environmental Laws and the
standards set out in Schedule 8 are complied with or exceeded. Unless
otherwise directed by the relevant Governmental Authority, the Generator
shall install and operate a suitable continuous emission and ambient air
monitoring system including at least four monitoring stations at
appropriate locations within a ten (10) kilometer radial distance from the
Facility. The Generator shall also install and operate on-line recorders
at the Facility and, unless otherwise directed, in the offices of the
relevant Governmental Authority.
8.4 The Generator shall provide an annual report on all relevant aspects
of the Generator's environmental facilities, activities and performance no
later than thirty (30) days following each Contract Year. The annual
report on environmental performance shall contain a statement of assurances
to the effect that all applicable environmental Laws have been complied
with or, where that is not the case, shall contain details of any failure
to comply with such environmental Laws and the actions instituted to
prevent such failures to recur.
9. FUEL SUPPLY
9.1 FUEL SUPPLY OBLIGATIONS
9.1.1 The Generator shall ensure that the Facility has sufficient
quantities of Fuel to enable each Unit to operate at eighty-five
percent (85%) of its Contracted Capacity on an annual basis from
its Commercial Operation Date until the last day of the Term.
9.1.2 The Generator shall not enter into a Fuel Purchase Agreement or
Fuel Transportation Agreement unless EGAT (i) has reviewed and
approved the terms and conditions thereof in accordance with
Section 9.1.3, or (ii) has been deemed to have so reviewed and
approved the terms and conditions thereof in accordance with
Section 9.1.4.
9.1.3 The Generator shall negotiate a Fuel Purchase Agreement and Fuel
Transportation Agreement which satisfy the principles set out in
Schedule 9. EGAT shall be afforded not less than thirty (30) days
to review the draft Fuel Purchase Agreement and draft Fuel
Transportation Agreement to determine whether or not such draft
agreements satisfy the principles set out in Schedule 9. EGAT shall
notify the Generator of its determination with respect to any such
draft agreement within thirty (30) days of receiving the draft
agreement. If EGAT determines that any such draft agreement does
not satisfy the principles set out in Schedule 9, EGAT shall
provide the Generator with the reasons for such determination and
propose changes EGAT reasonably deems necessary for the draft
agreement to satisfy such principles.
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9.1.4 EGAT shall be deemed to have completed its review and approved the
draft Fuel Purchase Agreement or draft Fuel Transportation
Agreement if it does not provide the Generator with a written
determination to the contrary together with the reasons for such
determination and EGAT's proposed changes within thirty (30) days
after the date of receipt of any such draft agreement.
9.1.5 EGAT's review, approval, objection or rejection of the draft Fuel
Purchase Agreement, Fuel Transportation Agreement or any proposed
amendment, modification or termination of such agreements shall
not:
(a) lessen, diminish or affect in any way the performance by the
Generator of its obligations under this Agreement or the
Project Agreements;
(b) increase, expand or affect in any way the obligations of EGAT
under this Agreement;
(c) affect the application or interpretation of the provisions of
this Agreement or the Project Agreements; or
(d) result in EGAT incurring any liability whatsoever for the
performance or consequences of the performance of the Fuel
Purchase Agreement or Fuel Transportation Agreement.
9.1.6 The Generator shall provide EGAT with copies of the fully executed
Fuel Purchase Agreement and Fuel Transportation Agreement on or
before the date specified in Section 11(g).
9.2 SUBSEQUENT FUEL SUPPLY AGREEMENTS
9.2.1 The Generator shall not terminate, modify or amend the Fuel
Purchase Agreement or Fuel Transportation Agreement without EGAT's
prior written consent. If either such agreement is terminated, the
Generator shall immediately negotiate a new Fuel Purchase Agreement
or a new Fuel Transportation Agreement.
9.2.2 The provisions set out in Section 9.1 shall apply mutatis mutandis
to any (i) new Fuel Purchase Agreement, (ii) new Fuel
Transportation Agreement, and (iii) documents relating to any
alternative Fuel arrangements made pursuant to Section 9.3.1.
9.3 FUEL STOCK
9.3.1 The Generator shall maintain at its expense on the Site at all
times a Fuel Stock sufficient to meet all of the Generator's Fuel
needs for a period of at least thirty (30) days in the event that
there is an interruption in the Generator's Fuel supply. In
determining whether the quantity of such Fuel Stock is sufficient,
the Generator shall take into account, among other things, the
maximum Fuel consumption rate of the Facility and the time required
to accomplish necessary replenishment.
9.3.2 The Generator shall provide EGAT with any information reasonably
requested by EGAT from time to time regarding the Fuel Stock and
shall also keep EGAT
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advised from time to time of any material modifications to its Fuel
Stock arrangements.
9.3.3 The Generator shall not be entitled to claim Force Majeure under
Section 14 for any interruption of the supply of Fuel to the
Facility until such interruption due to Force Majeure has continued
for a period of sixty (60) days from the date the interruption
occurred.
10. CRITICAL DATES AND DURATION OF AGREEMENT
10.1 INITIAL TERM
The Term of this Agreement shall begin on the Execution Date and shall
continue for a period of twenty-five (25) years from the Commercial
Operation Date of the Second Unit, unless otherwise extended or terminated
in accordance with the provisions of this Agreement.
10.2 SURVIVAL OF RIGHTS ON TERMINATION
The expiration or termination of this Agreement shall not affect any rights
or obligations which may have accrued prior to or in connection with such
expiration or termination, and shall not affect continuing obligations of
each of the Parties under this Agreement or any other agreement between the
Parties which are expressed to continue after such expiration or
termination.
10.3 EXTENSION OF AGREEMENT
The Term may be extended upon terms and conditions mutually satisfactory to
the Parties.
10.4 CRITICAL DATES
Scheduled Financial Close Date: 30 April 1999
Scheduled Construction Commencement Date: 1 May 1999
Scheduled NTF Energizing Date: 1 January 2001
Scheduled Energizing Date: 1 February 2001
Earliest Commercial Operation Date of the First Unit: 1 July 2001
Earliest Commercial Operation Date of the Second Unit: 1 January 2002
Scheduled Commercial Operation Date for the First Unit: 1 October 2001
Scheduled Commercial Operation Date for the Second Unit: 1 April 2002
10.5 EXTENSION OF CRITICAL DATES AND TERM
10.5.1 Each of the dates set out in Section 10.4 and the milestone dates
set out in Section 11 shall be extended by one day for each day
that a Force Majeure or Governmental Force Majeure preventing the
achievement of such date has occurred and is continuing.
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10.5.2 Each of the dates set out in Section 10.4 and the milestone dates
set out in Section 11 shall be extended by one day for each day
that the failure to achieve such date is due solely to the actions
or omissions of EGAT.
10.5.3 The Term of this Agreement shall be extended by one day for each
day of Force Majeure or Governmental Force Majeure occurring after
the Commercial Operation Date of the First Unit.
10.5.4 Failure to meet any of the critical dates set out in Section 10.4,
unless otherwise specifically stated in Section 12.2.1, shall not
be construed as a breach or default under this Agreement.
11. CONTRACTED MILESTONES
The Generator shall comply with the following milestones schedule in
connection with the development and construction of the Facility:
(a) EGAT shall have received from the Generator all drawings, reports and
certificates required under Sections 2.3.2, 2.3.3 and 2.8.3 with regard
to the design, construction and completion of the Facility on or before
the dates such materials are due thereunder;
(b) within fourteen (14) months after the Execution Date, EGAT shall have
received from the Generator evidence satisfactory to EGAT demonstrating
that the Generator has obtained all applicable Governmental Approvals,
including those related to air quality, easements and rights of way,
water use and discharge, solid waste and hazardous waste disposal
required for the construction, operation, and maintenance of the
Facility in accordance with the provisions of this Agreement, provided
that if any such Governmental Approval has not been obtained by such
date, the Generator shall provide to EGAT evidence demonstrating that
(i) such Governmental Approval could not be applied for by such date
other than due to an act or omission of the Generator, and (ii) the
Generator can reasonably be expected to obtain such Governmental
Approval before the date it is required to be obtained;
(c) within fourteen (14) months after the Execution Date, EGAT shall have
received from the Generator evidence acceptable to EGAT that the
Generator has acquired all necessary easements, rights-of-way and
authorizations needed to construct the Facility;
(d) within fourteen (14) months after the Execution Date, EGAT shall have
received from the Generator extracts or other evidence satisfactory to
EGAT demonstrating that contracts for the design and construction of
the Facility have been executed;
(e) within fourteen (14) months after the Execution Date, EGAT shall have
received from the Generator extracts or other evidence satisfactory to
EGAT that contracts for the procurement of major equipment have been
executed;
(f) within fourteen (14) months after the Execution Date, EGAT shall have
received from the Generator copies of the certificates of insurance
coverage, or insurance policies required;
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(f) EGAT fails to comply with or operate in conformity with any
material obligation of this Agreement.
12.1.2 In addition to any other remedy available to it, the Generator
shall be entitled to immediately terminate this Agreement by
written notice to EGAT for Events of Default by EGAT pursuant to
subsections (a) (following the thirty (30) day period specified in
subsection (a)), (b), (c), (d) and (e) of Section 12.1.1.
In the case of Section 12.1.1(f), the Generator shall give written
notice describing such Event of Default and EGAT shall be given
sixty (60) days from receipt of such notice to cure the default. If
the default cannot be cured within sixty (60) days with the
exercise of reasonable efforts, EGAT shall have an additional
period of time of one hundred and eighty (180) days in which to
cure the default, provided always that EGAT shall, throughout such
additional period, exercise reasonable, continuous efforts to cure
the default and continue to perform all its other obligations under
this Agreement during such period of cure. The Generator may (but
shall have no obligation to) grant any additional period of time
within which to cure any default. If EGAT fails to cure the default
within the relevant prescribed period, then the Generator may, in
addition to any other rights and remedies available to it,
immediately terminate this Agreement and consider EGAT in material
breach of its obligations under this Agreement.
12.1.3 After any termination of this Agreement, the Generator may exercise
any rights or remedies it has at law, including seeking monetary
compensation for damages, injunctive relief or specific
performance.
12.2 TERMINATION BY EGAT
12.2.1 Each of the following events shall be considered an EVENT OF
DEFAULT with respect to the Generator:
(a) the Generator defaults in the payment of any amount due and
payable under this Agreement and such default continues
unremedied for a period of thirty (30) days after the date on
which EGAT gives notice of the default to the Generator;
(b) damage to the Facility (excluding any damage caused by Force
Majeure) renders it substantially incapable of generating
electricity, and the Parties agree (or in the absence of such
agreement an Expert determines in accordance with Section 15)
that it is unlikely the Facility can be restored within thirty
(30) months from the date the damage occurred to a condition
such that (i) the Dependable Contracted Capacity established
for each Unit immediately following restoration would be at
least ninety percent (90%) of its Contracted Capacity, and (ii)
the Availability of each Unit over the six (6) months
immediately following restoration would exceed seventy-five
percent (75%) of its Actual Availability over the six (6)
months immediately preceding the date such damage occurred;
(c) damage to the Facility (by Force Majeure or any other cause)
rendered it substantially incapable of generating electricity,
and the Parties agreed (or in the absence of such agreement an
Expert determined in accordance with Section 15) that the
Facility could be restored to the condition
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described in Section 12.2.1(b) within thirty (30) months or
less from the date the damage occurred, and the Generator fails
to complete such restoration within thirty (30) months from the
date the damage occurred or within any lesser period agreed by
the Parties or determined by an Expert;
(d) the Generator is dissolved or liquidated, other than voluntary
dissolution or liquidation as part of a reorganization or
reincorporation;
(e) the Generator makes a general assignment of this Agreement or
any of its rights hereunder or of its interest in the Facility
for the benefit of its creditors;
(f) the Generator enters into voluntary insolvency proceedings or
is adjudicated bankrupt under any insolvency law as debtor;
(g) the Generator fails to comply with or operate in conformity
with any material obligation of this Agreement;
(h) the Commercial Operation Date of either Unit fails to occur by
its Scheduled Commercial Operation Date;
(i) the Generator abandons the engineering, design, construction or
operation and maintenance of the Facility for forty-five (45)
days or longer and, after receiving notice from EGAT, fails (i)
to indicate within ten (10) days its intent to resume such
activities within a period of time agreeable to EGAT, and (ii)
to resume such activities within such agreed period of time;
(j) there is a transfer of an interest in the Generator which falls
outside the permitted transfers set out in Section 24 and
EGAT's prior written approval of such transfer, to the extent
required by Section 24, has not been given, and such default
continues unremedied for a period of thirty (30) days from the
date on which such transfer occurred;
(k) without the prior written consent of EGAT, the Generator amends
the Fuel Purchase Agreement or Fuel Transportation Agreement,
or upon termination of the Fuel Purchase Agreement or Fuel
Transportation Agreement enters into a new Fuel Purchase
Agreement or Fuel Transportation Agreement, and the terms of
such amendment or new Fuel Purchase Agreement or Fuel
Transportation Agreement are such that the Generator's ability
to satisfy its obligations under this Agreement or EGAT's
rights under this Agreement are adversely affected;
(l) during any period of thirty-six (36) consecutive months, the
Actual Availability of the Units falls below sixty percent
(60%) of the Actual Availability that would be achieved were
both Units operated at their Contracted Capacity for all of the
hours in such thirty-six (36) month period, provided that the
accrual of such thirty-six (36) month period shall exclude
periods during which:
(i) it is not lawful for the Generator to operate the
Facility,
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(ii) the Generator is affected by Force Majeure or
Governmental Force Majeure, or
(iii) the Facility is being restored in accordance with Section
14.7; or
(m) the Generator fails to achieve Financial Close by the Scheduled
Financial Close Date or by such date fails to provide EGAT with
copies of written commitments from the Sponsors (or any of
their Affiliates) to provide capital contributions to the
Generator in amounts sufficient to enable the Generator to fund
development, construction and completion of the Facility.
12.2.2 In addition to any other remedy available to it, EGAT shall be
entitled to immediately terminate this Agreement by written notice
to the Generator for Events of Default by the Generator pursuant to
subsections (a) (following thirty (30) day period specified in
subsection (a)), (b), (d), (e), (f), (i), (j) (following the thirty
(30) day period specified in subsection (j)), (l) and (m) of
Section 12.2.1.
In the case of subsections (c), (g), (h) and (k) of Section 12.2.1,
EGAT shall give written notice describing such Event of Default and
the Generator shall be given sixty (60) days from receipt of such
notice to cure the default. If the default cannot be cured within
sixty (60) days with the exercise of reasonable efforts, the
Generator shall have an additional period of time of one hundred
and eighty (180) days in which to cure the default, provided always
that the Generator shall, throughout such additional period,
exercise reasonable, continuous efforts to cure the default and
continue to perform all of its other obligations under this
Agreement during such period of cure. EGAT may (but shall have no
obligation to) grant any additional period of time within which to
cure any default. If the Generator fails to cure the default within
the relevant prescribed period or any additional period granted by
EGAT at its sole discretion, then EGAT may, in addition to any
other rights and remedies available to it, immediately terminate
this Agreement and consider the Generator in material breach of its
obligations under this Agreement.
12.2.3 After any termination of this Agreement, EGAT may exercise any
rights or remedies it has at law, including seeking monetary
compensation for damages, injunctive relief or specific
performance.
12.3 STEP-IN RIGHTS
12.3.1 EGAT shall have the right, but under no circumstances the
obligation, to assume operational responsibility for the Facility
(in the capacity of an operator only) in the place and instead of
the Generator in order to continue operation of the Facility or
complete any necessary repairs so as to assure uninterrupted
availability of electrical energy from the Facility.
Such step-in rights shall arise upon the occurrence and continuance
of an Event of Default with respect to the Generator which could
reasonably be expected to materially adversely affect the
Generator's ability to operate and maintain the Facility in
accordance with this Agreement.
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EGAT shall not exercise such step-in rights until any applicable
cure period specified in Section 12.2.2 has expired, provided that
EGAT may step-in at any earlier time at the request of the
Financing Parties if a right for the Financing Parties to step-in
has arisen under the Financing Documents. For so long as the
Financing Documents remain in effect, EGAT shall not exercise step-
in rights hereunder (i) without first obtaining the consent of the
Financing Parties, or (ii) if operation of the Facility has been
assumed by any Financing Party or any approved assignee or designee
of the Financing Parties.
The Generator shall use its reasonable efforts to cause the
Financing Parties specifically to acknowledge such step-in rights
of EGAT in the Financing Documents.
EGAT may require issues and conditions in addition to those
addressed in this Section 12.3.1 to be clarified to EGAT's
satisfaction before EGAT exercises the step-in rights provided
hereunder. In particular, the Generator shall:
(a) assign to EGAT or its designated agent or contractor, within
two (2) Business Days of the event giving rise to EGAT's
rights, the Generator's rights in and to all agreements
necessary to operate the Facility; and
(b) take all steps necessary to permit EGAT to exercise as
operator of the Facility the Generator's rights under all
permissions and licenses to the extent such rights are
necessary for EGAT to operate the Facility and provide EGAT
with access to all design manuals, construction drawings and
other documentation required to operate the Facility.
12.3.2 During any period in which EGAT exercises its right to assume the
operations of the Facility pursuant to this Section 12.3, EGAT
shall continue making Availability Payments and Energy Payments to
the Generator in accordance with the terms of this Agreement. In no
event shall EGAT's decision to operate the Facility be deemed to be
a transfer of title or a transfer of the Generator's obligations as
owner thereof, but EGAT shall be deemed to be only the operator of
the Facility.
During any period when EGAT shall be operating the Facility, EGAT
shall:
(a) be entitled to reasonable remuneration for EGAT's services as
an operator charged at then international rates of remuneration
for comparable services; and
(b) meet any payments due from the Generator, including payments
for fuel, maintenance, repairs, insurance, taxes and other
operating costs of the Facility, together with all regularly
scheduled payments under the Financing Documents of principal,
interest, fees, indemnities, reserves, and other amounts owing
(in each case pro-rated for the amount attributable to such
period), but only to the extent that the Generator is unable to
meet any such payments.
The Parties shall cooperate with each other and execute and deliver
such documents as may be necessary or desirable to accomplish the
foregoing. The remuneration and payments referred to in subsections
(a) and (b) of this Section 12.3.2 which become payable during any
such period shall be regarded as funds
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advanced by EGAT to the Generator. EGAT shall be entitled to
payment of such amounts in full and with interest calculated at the
Default Rate from the date such payment is due. EGAT shall obtain
such payment by deduction from Availability Payments and Energy
Payments due to the Generator including, where such deduction is
insufficient to repay EGAT fully within the step-in period, the
continuation of such deduction after the end of such step-in
period, provided that such amounts shall be subordinated to amounts
owed to the Financing Parties.
12.3.3 During any period when EGAT is operating the Facility, EGAT shall
exercise its reasonable efforts to produce and deliver electrical
energy to the EGAT System, subject to the Facility being operable
at the time of EGAT's takeover or later being made operable by
repairs or otherwise. Throughout such period of time, EGAT shall
exercise due care in operating and maintaining the Facility in
accordance with Prudent Utility Practices. EGAT shall have no more
liability to the Generator than would a third party operation and
maintenance contractor with respect to the operation and
maintenance of the Facility by EGAT during the exercise of such
step-in rights hereunder. For the avoidance of doubt, such
liability shall not include any liability for failure to provide
Availability.
12.3.4 EGAT shall have the right to discontinue making payments under
Section 12.3.2 and to terminate this Agreement in accordance with
Section 12.2.2 if at any time EGAT reasonably determines that the
Event of Default leading to such exercise by EGAT of its step-in
rights cannot be cured, or that the Generator is unlikely to repay,
or to be able to repay, the funds advanced by EGAT under Section
12.3.2.
EGAT shall also have the right on fifteen (15) days' prior written
notice to the Generator to return the operational responsibility
for the Facility to the Generator, provided that EGAT shall return
the Facility to the Generator in a condition no worse than that
immediately prior to the assumption of the operational
responsibility for the Facility by EGAT, ordinary wear and tear
excepted.
Notwithstanding the foregoing, EGAT shall not be responsible for or
have any liability resulting from any conditions of the Facility or
at the Site that existed prior to EGAT's exercise of its step-in
rights.
12.3.5 The operation of the Facility by EGAT shall not relieve EGAT from
its obligations to perform under this Agreement. The failure by
EGAT to meet its obligations as a responsible operator of the
Facility under Section 12.3.3 shall not give rise to an Event of
Default with respect to the Generator for which EGAT shall have the
right to exercise remedies under Section 12.2.3. For the avoidance
of doubt, notwithstanding the provisions of this Section 12.3.5,
EGAT shall retain all those rights provided under Section 12.3.4.
12.3.6 Upon the curing of the Event of Default which has led to the
exercise by EGAT of its step-in rights, EGAT shall return the
operation of the Facility to the Generator with reasonable
promptness.
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12.4 OTHER RIGHTS TO TERMINATE
Without prejudice to any other remedy to which either Party may be entitled
for breach of this Agreement, the Parties agree that Sections 12, 14.6 and
14.7 state the only circumstances in which either Party may unilaterally
terminate this Agreement.
13. SECURITIES AND LIQUIDATED DAMAGES
13.1 ESTABLISHMENT OF DEVELOPMENT SECURITY
On the Execution Date the Generator shall provide to EGAT the Development
Security in the form of a direct-pay letter of credit or a letter of
guarantee or a cash escrow account acceptable to EGAT in an amount equal to
five hundred (500) Baht per kW of the sum of the Contracted Capacities of
the Units in order to secure the Generator's performance of its obligations
under this Agreement. The Generator shall maintain the Development
Security until the Commercial Operation Date of the Second Unit. The
Development Security shall be obtained from one or more Thai banks which
are listed in Schedule 21 or which satisfy the credit standards set out
below.
If the Generator provides the Development Security in the form of a letter
of credit, the letter of credit shall be issued either (i) for a term not
to expire before the Commercial Operation Date of the Second Unit, or (ii)
on the condition that such letter of credit expressly provides to EGAT the
right to draw down the amount of the letter of credit prior to termination
of the letter of credit, if it has not been extended for any additional
period of time that may be required to cover the period through the
Commercial Operation Date of the Second Unit. If the Generator provides
the Development Security in the form of a letter of guarantee, the
guarantee shall be substantially in the form set out in Schedule 12.
EGAT will appraise on a yearly basis the value of all non-cash securities
provided as the Development Security. If the credit rating of any Thai
bank from which the Generator has obtained the Development Security falls
below BBB+ as measured by Standard and Poor's Ratings Group, Baal as
measured by Moody's Investors Services or AA as measured by the Thai Rating
Information Services, then EGAT may at its sole discretion require the
Generator to post additional or replacement security from a Thai bank with
a rating not less than those stated above in order to compensate for the
change in value of the Development Security.
If there is a failure to comply with this provision, EGAT may terminate
this Agreement pursuant to Sections 12.2.1(g) and 12.2.2.
13.2 EGAT'S RIGHT TO RETAIN DEVELOPMENT SECURITY AS LIQUIDATED DAMAGES
The Generator acknowledges and understands that EGAT has entered into this
Agreement in reliance on and in consideration of the Generator's
representation that the Units will be in operation no later than their
respective Scheduled Commercial Operation Dates, and that EGAT will include
the Units in its various capacity forecasts. The Generator further
acknowledges and understands that in order to meet its obligations to its
retail and wholesale customers as a public utility, EGAT must have adequate
assurance that construction of the Facility is proceeding in a timely
fashion in order to forecast adequately and meet the EGAT System's
capacity needs as well as to avoid incurring production costs higher than
those planned by EGAT.
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Based on the foregoing, the Generator agrees that EGAT shall have the right
in each instance to retain so much of the Development Security as is set
out below, plus accrued interest thereon, as liquidated damages if any one
or more of the following milestone dates have not been satisfied (unless
any such milestone date has not been met due to Force Majeure or the fault
of EGAT) within the time periods herein established:
(a) One quarter of one percent (0.25%) for each of the detailed
engineering drawings, reports, and certificates that EGAT has not
received from the Generator in accordance with Section 11(a);
provided, however, that the total amount able to be assessed against
the Generator for failure to provide such drawings, reports and
certificates shall not exceed five percent (5%) of the amount of the
Development Security;
(b) Ten percent (10%) if EGAT has not received all required environmental
permits and other Governmental Approvals required to construct the
Facility in accordance with Section 11(b);
(c) Five percent (5%) if EGAT has not received any extracts or other
evidence of the execution of the contracts for the procurement of
major equipment in accordance with Section 11(e);
(d) Five percent (5%) if EGAT has not received the Fuel Purchase Agreement
and the Fuel Transportation Agreement, if any in accordance with
Sections 9.1.3 and 11(g);
(e) Ten percent (10%) if EGAT has not received copies of the principal
Financing Documents in accordance with Section 11(h). For purposes of
this Section 13.2(e), satisfactory copies of the principal Financing
Documents shall consist of binding commitments of the Financing
Parties and equity participants sufficient to fund one hundred percent
(100%) of construction and permanent financing; and
(f) Fifteen percent (15%) if the Generator shall have failed to commence
construction in accordance with Section 11(i).
EGAT shall return the remaining portion of the Development Security
together with all interest accrued thereon, if any, following the payment
of any amounts due to EGAT hereunder to the Generator upon thirty (30) days
after the earlier of (i) satisfaction of the requirements for additional
security in accordance with Section 13.5 after the Commercial Operation
Date of the Second Unit, and (ii) the termination of this Agreement in
accordance with Section 12.1, 12.2, 14.6 or 14.7. Notwithstanding the
foregoing, EGAT shall return to the Generator fifty percent (50%) of that
portion of the Development Security retained by EGAT in accordance with
this Section 13.2 if the Commercial Operation Date of the First Unit occurs
by its Scheduled Commercial Operation Date and fifty percent (50%) of such
portion of the Development Security if the Commercial Operation Date of the
Second Unit occurs by its Scheduled Commercial Operation Date.
If the Commercial Operation Date of either Unit fails to occur by its
Scheduled Commercial Operation Date, in addition to any amounts retained by
EGAT in accordance with this Section due to the Generator's failure to meet
any of the milestones and the Commercial Operation Date of either Unit, the
Generator shall pay liquidated damages to EGAT in accordance with Sections
2.10.3, 2.10.5 and 19.2.
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13.3 LIQUIDATED DAMAGES FOR CONTRACTED CAPACITY DEFICIENCIES
If the Dependable Contracted Capacity of either Unit on its Commercial
Operation Date is less than ninety-five percent (95%) of its Contracted
Capacity, the Generator shall pay to EGAT on a one-time basis only for such
Unit, a sum equal to four thousand (4,000) Baht per kW for the difference
between such Dependable Contracted Capacity of the Unit and ninety-five
percent (95%) of the Unit's Contracted Capacity as liquidated damages for
the detrimental impact upon EGAT's generation planning. EGAT shall be
entitled to recover the amount of such liquidated damages from the
Development Security, and the Generator shall pay EGAT any amount of such
liquidated damages which exceeds the available amount of the Development
Security in accordance with Section 19.2. Notwithstanding subsequently
established increases in the Dependable Contracted Capacity of the Unit
pursuant to Section 2.11, EGAT shall not be required to refund any portion
of the liquidated damages previously paid to EGAT pursuant to this Section
13.3.
13.4 PAYMENTS FROM THE SECURITY
To the extent EGAT is owed damages as a result of the Generator's breach of
this Agreement (other than for a failure to meet the milestones set out in
Section 13.2 or for a deficiency in the Contracted Capacity of either Unit
under Section 13.3) and EGAT has previously not been compensated therefor,
appropriate amounts of the Development Security shall be retained by EGAT.
The return of the Development Security to the Generator shall not prejudice
the rights of EGAT to claim compensation arising from this Agreement.
13.5 ADDITIONAL SECURITY
13.5.1 As soon as reasonably practicable, but no later than six (6) months
after the Commercial Operation Date of the Second Unit, and before
the return of the Development Security under Section 13.2, the
Generator shall execute in favor of EGAT mortgages over the
buildings, machinery and real property assets comprising the
Facility. The mortgages shall secure the Generator's performance of
its obligations to EGAT under this Agreement up to an amount equal
to one billion (1,000,000,000) Baht and shall be subordinate at all
times to the amounts secured under the mortgages and security
interests granted to the Financing Parties up to the greater of:
(a) the sum of:
(i) all amounts secured under or contemplated to be secured
under the Financing Documents at Financial Close
(including amounts payable to providers of interest rate
swap agreements or other reasonable hedging arrangements
required by the Financing Parties or issuers of letters
of credit in respect of foreign currency exchange
reserve requirements or debt service reserve
requirements, but excluding the amount of any cost
overrun facilities relating to the construction of the
Facility other than the amount of the overrun facilities
that are drawn down upon for (i) capital improvements
which are required by Changes-in-Law, changes to the
Grid Code, Force Majeure or Prudent Utility Practices,
(ii) increased costs resulting from or attributable to
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EGAT's delay or failure in performing its obligations
under this Agreement, or (iii) any other uses, provided
that in the case of this subclause (iii) the amount of
equity committed or infused by or on behalf of the
Generator into the Project is greater than the sum of
(i), (ii) and (iii) by one billion (1,000,000,000)
Baht), plus
(ii) the amount of any additional financing obtained by the
Generator after the Financial Close for additional
working capital needs or capital improvements which are
required by Changes-in-Law, changes to the Grid Code,
Force Majeure (as approved by EGAT) or Prudent Utility
Practices; or
(b) the fair market value of the Project for the remaining useful
life of the Facility as reasonably determined by the Financing
Parties at the time of any additional financing or refinancing
minus one billion (1,000,000,000) Baht.
13.5.2 If requested by the Generator, EGAT and the Generator shall from
time to time, in connection with any financing or refinancing by
the Generator, execute subordination agreements giving effect to
the arrangements described in Section 13.5.1 and such other
documents as may be requested by the Financing Parties to evidence
the subordination contemplated in Section 13.5.1. EGAT acknowledges
that it shall have no rights to exercise any of its rights under
the mortgages executed in its favor pursuant to Section 13.5.1
during any period in which any Financing Documents are in force and
effect until such time as the Financing Parties have exercised
their mortgage rights to enforce their remedies.
13.5.3 The Generator shall bear its own costs and all reasonable costs
incurred by EGAT in connection with the negotiation and execution
of the mortgage granted to EGAT and, when such is requested by the
Generator, in connection with the subordination agreements,
consents, releases and related documents required by any Financing
Parties from time to time, and all other documents in connection
therewith, and shall pay the mortgage registration fees to register
the mortgage and for re-registrations required in connection with
refinancings or additional financings.
13.5.4 Subject to the continuing observation of the restrictions set out
in Section 13.5.1, the Generator shall be entitled to refinance the
Project after the Commercial Operation Date of the Second Unit. The
Generator shall obtain EGAT's prior written consent for any
refinancing of the Project before the Commercial Operation Date of
the Second Unit. EGAT shall provide such consent if in its judgment
the refinancing will not have a material adverse impact on EGAT's
interests in the completion of the Facility in accordance with the
terms of this Agreement.
In the case of a refinancing, EGAT agrees that the Financing
Parties shall continue to enjoy priority over EGAT with regard to
their respective security interests in the Facility. EGAT further
agrees to execute any consents reasonably requested by the
Financing Parties for subsequent refinancings or financings (or, if
necessary, a release of its mortgage) from time to time in order to
enable any subsequent or additional secured Financing Party to
enjoy the priority contemplated under Section 13.5.1 and the
Generator agrees to re-register the mortgage granted to EGAT, if
applicable.
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13.6 REASONABLE LIQUIDATED DAMAGES
The Parties acknowledge that where liquidated damages for either the
Generator's or EGAT's failure to perform their respective obligations are
set out in this Section 13 and Section 2, such liquidated damages (i) are
reasonable and appropriate measures of the damages for such delays or such
failures, (ii) do not represent a penalty or consequential damages for
losses sustained by EGAT or the Generator as a result of such failures, and
(iii) shall be the exclusive remedies for the failure to achieve the
milestone obligations set out in Section 11, provided that such liquidated
damages are not intended to compensate either Party for the damage that may
result from termination of this Agreement as a result of the continuation
of such failures.
14. FORCE MAJEURE
14.1 OVERVIEW
14.1.1 For the purposes of this Agreement, Force Majeure shall mean an
event, condition, or circumstance, including and the effects
thereof, beyond the reasonable control and without the fault or
negligence of the Party claiming Force Majeure, which, despite all
reasonable efforts of the Party claiming Force Majeure to prevent
it or mitigate its effects, causes a delay or disruption in the
performance of any obligation imposed hereunder. Subject to the
foregoing, Force Majeure shall include:
(a) unusually severe weather conditions;
(b) epidemic or plague;
(c) acts of war (whether war has been declared or is undeclared),
acts of force by a foreign nation, or embargo;
(d) strike or work stoppage (other than those solely affecting the
Party claiming the same as Force Majeure), riots or acts of
terrorists;
(e) Change-in-Law;
(f) failure (other than a failure due to an act or omission of the
Generator) to obtain or renew any required Governmental
Approval relating to the ownership, construction, financing,
operation or maintenance of the Facility, or the performance
of the obligations under this Agreement;
(g) accident, earthquake, sabotage fire or explosion;
(h) expropriation or compulsory acquisition of the Facility, any
material assets or rights, any shares or other interest of the
Generator, or any other act or omission by any Governmental
Authority (other than (i) lawful actions due to an act or
omission by the Generator or its contractors not in compliance
with Law, or (ii) the enforcement of the terms of this
Agreement or the Project Agreements in accordance with the
dispute resolution procedures contemplated thereunder) which
adversely affects the Generator or any of its rights or the
performance of its obligations under this Agreement or any
Project Agreement relating to the Facility to which the
Generator is a party; and
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(i) any Force Majeure affecting the performance of any Person that
is a party to any material maintenance, construction, service,
fuel supply or other material contract between the Generator
and such Person relating to the ownership, construction,
operation or maintenance of the Facility.
14.1.2 For purposes of this Agreement, GOVERNMENTAL FORCE MAJEURE shall
mean those events of Force Majeure described in Section 14.1.1(c),
(e), (f) and (h) in which the action or inaction of Governmental
Authorities is the controlling or contributing force which
determines or causes the occurrence of such events or the
continuation of the effects thereof. For the avoidance of doubt,
(i) events of Force Majeure shall not include Governmental Force
Majeure for purposes of Sections 14.4 and 14.6, and (ii) if an
event of Governmental Force Majeure occurs before the privatization
of EGAT and is continuing when EGAT is privatized, the event shall
continue to be treated as Governmental Force Majeure irrespective
of whether the provisions relating to Governmental Force Majeure
have been eliminated pursuant to Section 27.1.
14.1.3 For the avoidance of doubt, mechanical or electrical breakdown or
failure of equipment, machinery or plant owned or operated by
either Party due to the manner in which such equipment, machinery
or plant has been operated or maintained (whether or not by such
Party) shall not itself constitute Force Majeure.
14.1.4 Subject to the limitations set out in this Agreement, if either
Party is rendered unable by reason of a Force Majeure to perform,
wholly or in part, any obligation set out in this Agreement, then
upon such Party giving notice as specified in Section 14.2 and full
particulars of such event, such obligations of such Party shall be
suspended or excused to the extent of such Force Majeure.
14.2 NOTICE OF FORCE MAJEURE AND CONSEQUENCES
The Party claiming the Force Majeure shall as soon as reasonably
practicable following the occurrence of Force Majeure:
(a) notify the other Party of the Force Majeure, identifying the nature of
the event and the duration of its effect which the Party claiming
Force Majeure believes to be reasonably likely;
(b) afford the other Party reasonable access to its facilities for
obtaining further information about the event, including the Facility
or EGAT System, for site inspection;
(c) use, at its own cost, all reasonable efforts to remedy its inability
to perform and to resume full performance hereunder as soon as
practicable;
(d) keep such other Party reasonably apprised of such efforts; and
(e) provide written notice of the resumption of performance hereunder.
The foregoing shall be conditions to the ability of a Party to obtain
relief from its obligations under this Agreement due to Force Majeure.
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14.3 LIMITATIONS
The Party claiming Force Majeure shall not be entitled to suspend
performance under this Agreement for any greater scope or longer duration
than is required by the Force Majeure or the delay occasioned thereby.
Without otherwise limiting the payment rights and obligations under Section
14.4, during any period of Force Majeure or Governmental Force Majeure,
EGAT shall continue to make Availability Payments in accordance with
Schedule 2 for any Availability provided by the Generator that EGAT remains
capable of Dispatching. Neither Party shall be relieved of its obligations
under this Agreement nor shall any obligations of a Party be suspended
solely because there may be increased costs or other adverse economic
consequences incurred through the performance of such obligations.
Obligations of the Parties that are required to be completely performed
prior to the occurrence of Force Majeure shall not be excused as a result
of such occurrence. The failure or inability of either Party to satisfy a
payment obligation that has arisen under this Agreement shall not be
excused by Force Majeure.
14.4 PAYMENT RIGHTS AND OBLIGATIONS DURING FORCE MAJEURE
14.4.1 If Force Majeure affecting the Generator occurs after the
Commercial Operation Date of either Unit, EGAT shall make
Availability Payments to the Generator only to the extent the Unit
is Available to deliver electrical energy to EGAT.
14.4.2 EGAT shall make Availability Payments from the Scheduled Commercial
Operation Date of either Unit (adjusted as described below) if
Governmental Force Majeure affecting either Party occurs before the
Commercial Operation Date of the Unit and delays the occurrence of
its Commercial Operation Date past its Scheduled Commercial
Operation Date. The amount of each such Availability Payment shall
be calculated using the Contracted Capacity of the Unit.
For the purposes of determining the date such Availability Payments
shall commence, the Scheduled Commercial Operation Date of the Unit
(i) shall be extended by one day for each day by which the
occurrence of the Commercial Operation Date of the Unit is delayed
due to causes attributable to the Generator, but (ii) shall not be
extended pursuant to Section 10.5.1 for such Governmental Force
Majeure. EGAT shall make such Availability Payments until the
earlier of (i) the discontinuation of such Governmental Force
Majeure (including the effects thereof), or (ii) the termination of
this Agreement pursuant to Section 14.6.3.
14.4.3 If Governmental Force Majeure affecting either Party occurs after
the Commercial Operation Date of either Unit, EGAT shall continue
to make Availability Payments to the Generator with respect to the
Unit. Each such Availability Payment shall be:
(a) in an amount equal to the average of the Availability Payments
made to the Generator with respect to the Unit over the period
of six (6) months preceding the Governmental Force Majeure,
excluding periods of Planned Outages or Force Majeure;
(b) if the Governmental Force Majeure occurs less than six months
after the Commercial Operation Date of the Unit, in an amount
equal to the average of Availability Payments made to the
Generator with respect to
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the Unit over the period from its Commercial Operation Date to
the Governmental Force Majeure, excluding periods of Planned
Outages or Force Majeure; or
(c) if the Governmental Force Majeure occurs before the end of the
first Billing Period after the Commercial Operation Date of
either Unit, in an amount calculated using the Dependable
Contracted Capacity in effect for the Unit on the day before
the Governmental Force Majeure occurred.
EGAT shall make payments in accordance with this Section until the
earlier of (i) discontinuation of such Governmental Force Majeure
(including the effects thereof), or (ii) the termination of this
Agreement pursuant to Section 14.6.4.
14.4.4 If the Commercial Operation Date of the First Unit fails to occur
by its Scheduled Commercial Operation Date due to Force Majeure
affecting the New Main Transmission Line, from the Scheduled
Commercial Operation Date of the Unit (adjusted as described below)
EGAT shall pay the Generator its costs of servicing debt drawn down
and expended by the Generator before or on the date such Force
Majeure occurred and any unavoidable costs the Generator
necessarily or reasonably incurs thereafter. For the purposes of
determining the date such payments shall commence, the Scheduled
Commercial Operation Date of the First Unit (i) shall be extended
by one day for each day by which the occurrence of its Commercial
Operation Date is delayed due to causes attributable to the
Generator, but (ii) shall not be extended pursuant to Section
10.5.1 for Force Majeure affecting the New Main Transmission Line.
If Force Majeure affecting the New Main Transmission Line occurs
after the Commercial Operation Date of the First Unit and before
the Commercial Operation Date of the Second Unit, EGAT shall pay
the Generator the greater of (i) Availability Payments with respect
to the First Unit in amounts determined in accordance with Section
14.4.5(a), (b) or (c), or (ii) the Generator's costs of servicing
debt drawn down and expended before or on the date such Force
Majeure occurred and any unavoidable costs the Generator
necessarily or reasonably incurs thereafter. EGAT shall commence
making such payments on the date such Force Majeure occurs.
EGAT shall make payments pursuant to this Section 14.4.4 until the
earlier of (i) the discontinuation of such Force Majeure (including
the effects thereof), or (ii) the termination of this Agreement
pursuant to Section 14.6.2. If any payments made under this Section
14.4.4 (other than Availability Payments with respect to the First
Unit) include amounts which are applied to reduce the principal of
debt under the Financing Documents, the Parties shall consult each
other in good faith to determine any equitable adjustment to the
Availability Payments required to prevent EGAT from compensating
the Generator a second time after the Commercial Operation Date of
either Unit for the same principal amounts.
14.4.5 If Force Majeure affecting EGAT occurs after the Commercial
Operation Date of the Second Unit, EGAT shall pay the Generator its
costs of servicing debt drawn down and expended by the Generator
before or on the date such Force Majeure occurred and any
unavoidable costs the Generator necessarily or reasonably incurs
after such date. EGAT shall make such payments to the Generator
during any period of Force Majeure which affects EGAT after the
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Commercial Operation Date of the Second Unit until the aggregate of
all such periods of Force Majeure affecting EGAT equals six (6)
months. Thereafter, EGAT shall make Availability Payments to the
Generator during any period of Force Majeure that affects EGAT.
Such Availability Payments with respect to each Unit shall be:
(a) in an amount equal to the average of the Availability Payments
made to the Generator for the Unit over the period of six (6)
months preceding the Force Majeure, excluding periods of
Planned Outages or Force Majeure;
(b) if the Force Majeure occurred less than six (6) months after
the Commercial Operation Date of the Unit, in an amount equal
to the average of Availability Payments made to the Generator
with respect to the Unit from its Commercial Operation Date to
the date the Force Majeure occurred, excluding periods of
Planned Outages or Force Majeure; or
(c) if the Force Majeure occurs before the end of the first
Billing Period after the Commercial Operation Date of the
Unit, in an amount calculated using the Dependable Contracted
Capacity in effect for the Unit on the day before the Force
Majeure occurred.
EGAT shall make payments in accordance with this Section 14.4.5
until the earlier of (i) discontinuation of the Force Majeure
(including the effects thereof), or (ii) the termination of this
Agreement pursuant to Section 14.6.2.
14.4.6 Beginning on the date that the aggregate of periods of Force
Majeure affecting EGAT reaches six (6) months, EGAT shall pay the
Generator an amount representing the portion of Availability
Payments that were suspended in accordance with Section 14.4.5
during such periods of Force Majeure. Such amount shall be:
(a) the sum of the Availability Payments that would have been paid
pursuant to Section 14.4.5 (adjusted as set out in Section
14.4.7) during such periods of Force Majeure if such periods
of Force Majeure had occurred after preceding periods of Force
Majeure affecting EGAT had reached an aggregate of six (6)
months; less
(b) the sum of all payments made by EGAT to the Generator pursuant
to Section 14.4.5 during such periods of Force Majeure.
EGAT shall pay this amount to the Generator over a period of
twenty-four (24) months in equal monthly instalments added to the
Availability Payments made during such period, provided that (i)
EGAT shall pay such instalments whether or not its obligation to
make Availability Payments is excused in whole or in part during
such twenty-four (24) month period, and (ii) if this Agreement is
terminated before the end of such twenty-four (24) month period,
EGAT shall pay the sum of the unpaid instalments upon termination.
14.4.7 Whenever EGAT makes Availability Payments to the Generator in
accordance with Section 14.4.2, 14.4.3, 14.4.4 or 14.4.5, such
payments shall be:
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(a) decreased by all costs which, as a result of either Force
Majeure or Governmental Force Majeure, the Generator either
did not incur or reasonably need not have incurred without
materially and adversely affecting the condition of the
Facility or its ability to resume generation of electricity
upon the discontinuation of Force Majeure or Governmental
Force Majeure;
(b) decreased by the proceeds of any business interruption
insurance received by the Generator as a result of the Force
Majeure or Governmental Force Majeure;
(c) decreased by the amount of any Availability Payments made for
Actual Availability pursuant to Section 14.3; and
(d) increased by any additional costs necessarily or reasonably
incurred by the Generator as a result of the Force Majeure or
Governmental Force Majeure.
14.4.8 If the Dependable Contracted Capacity that is established for
either Unit on its Commercial Operation Date is less than its
Contracted Capacity, then any Availability Payments made to the
Generator before the Unit's Commercial Operation Date in accordance
with Section 14.4.2 shall be recalculated using the Dependable
Contracted Capacity established for the Unit on its Commercial
Operation Date. If the Availability Payments made to the Generator
with respect to the Unit before its Commercial Operation Date
exceed the amount reached by the recalculation, EGAT shall be
entitled to deduct an amount equal to the excess from future
payments due to the Generator by EGAT together with interest on
such amount at the Overdraft Rate. Such deductions shall be made
from such future payments pro-rata over the same period of time in
which the excess Availability Payments were made.
14.5 PAYMENTS DURING EXTENSION OF TERM
During any extension of the Term under Section 10.5.3 (or, if pursuant to
Section 2.10.4 or 14.4.2 EGAT has made Availability Payments with respect
to either Unit before its Commercial Operation Date, beginning on the date
in the Term after which the application of Table 1 of Schedule 2 to
determine Availability Payments for the Unit has been completed), EGAT
shall be entitled to receive electrical energy from the Generator by making
payments to the Generator in amounts determined as follows:
(a) Energy Payments calculated in accordance with Schedule 3 and fixed
operation and maintenance costs calculated in accordance with Schedule
2 with respect to each Unit for a period representing the same number
of days for which EGAT made (i) Availability Payments for the Unit
pursuant to Sections 2.10.4, 14.4.2, 14.4.3, 14.4.4 and 14.4.5, or
(ii) payments for the Unit pursuant to Section 14.4.6;
(b) if the aggregate of periods of Force Majeure affecting EGAT during the
Term (before any adjustment pursuant to Section 10.5.3) is less than
six (6) months, EGAT shall make Availability Payments with respect to
each Unit for the same number of days in such extension as the
aggregate of such periods of Force Majeure, provided that (i) such
Availability Payments shall be calculated using the rates set out in
Schedule 2 that would have applied during such periods of Force
Majeure, and (ii) such Availability Payments shall be reduced by
amounts
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paid by EGAT to the Generator during such periods of Force Majeure
pursuant to Sections 14.3 and 14.4.5; and
(c) Availability Payments to the extent of each Unit's Availability for
any portion of such extension attributable to Force Majeure affecting
the Generator after the Commercial Operation Date of the Second Unit,
provided that (i) such Availability Payments shall be calculated using
the rates set out in Schedule 2 that would have applied during such
periods of Force Majeure, and (ii) such Availability Payments shall be
reduced by the amount of any payments made to the Generator with
respect to the Unit pursuant to Section 14.4.1.
14.6 TERMINATION
14.6.1 Subject to Section 14.7, if Force Majeure affecting the Generator
occurs before or after the Commercial Operation Date of the Second
Unit and continues for a period exceeding one (1) year, either
Party may terminate this Agreement by giving the other Party thirty
(30) days written notice of termination.
14.6.2 If Force Majeure affecting the New Main Transmission Line occurs
before the Commercial Operation Date of the First Unit and
continues for a period of twenty-four (24) months, EGAT may
terminate this Agreement by giving the Generator thirty (30) days
written notice of termination. If any other Force Majeure affecting
EGAT occurs before or after the Commercial Operation Date of the
First Unit, EGAT may terminate this Agreement by giving the
Generator thirty (30) days written notice after such Force Majeure
has continued for twelve (12) months. Upon any termination of this
Agreement in accordance with this Section 14.6.2, EGAT shall
purchase the Generator's right, title and interest in and to the
Facility and all other assets of the Generator for an amount which
shall be:
(a) the aggregate amount outstanding on the date of such purchase
under the Financing Documents, including reasonable
termination costs due under such Financing Documents, and
under any loans from shareholders to the Generator; plus
(b) an amount equal to the sum of all amounts of registered and
paid-up share capital issued by the Generator and any share
premiums received by the Generator; plus
(c) an amount equal to any earnings retained by the Generator
(including statutory reserves); less
(d) the proceeds of any insurance received by the Generator as a
result of such Force Majeure.
14.6.3 Subject to Section 14.7, if Governmental Force Majeure affecting
either Party occurs before the Commercial Operation Date of the
Second Unit and continues for a period exceeding one (1) year,
either Party may terminate this Agreement by giving the other Party
thirty (30) days written notice of termination, whereupon EGAT
shall purchase the Generator's right, title, and interest in and to
the Facility and all other assets of the Generator for an amount
which:
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(a) if EGAT has elected to terminate this Agreement, shall be the
sum of (i) the purchase price as calculated in Section 14.6.2,
plus (ii) a return on the amount determined in Section
14.6.2(b) at the rate of fifteen percent (15%) per annum,
calculated from the date of the investment in the Generator to
the date of EGAT's purchase hereunder; or
(b) if the Generator has elected to terminate this Agreement,
shall be the purchase price as calculated in Section 14.6.2.
14.6.4 Subject to Section 14.7, if Governmental Force Majeure affecting
either Party occurs after the Commercial Operation Date of the
Second Unit and continues for a period exceeding one (1) year, EGAT
may terminate this Agreement by giving the Generator thirty (30)
days written notice of termination, whereupon EGAT shall purchase
the Generator's right, title, and interest in and to the Facility
and all other assets of the Generator for an amount which shall be
agreed between the Parties, provided that termination of this
Agreement shall not take effect until such amount is agreed. Such
agreed amount shall be an amount which:
(a) is not less than the aggregate amount outstanding under the
Financing Documents on the date of such purchase, including
reasonable termination costs payable under the Financing
Documents and an amount equal to any earnings retained by the
Generator (including statutory reserves); and
(b) takes into account the Term of this Agreement remaining on the
date such amount is agreed, the condition and historical
performance of the Facility, the remaining useful life and the
economic value of the Facility's generating capacity to either
Party over the remainder of its useful life, the depreciated
cost of the Facility on the books of the Generator, the
Generator's achieved return on equity, and the nature of the
Governmental Force Majeure and the ability to cure such
Governmental Force Majeure.
If the Parties are unable to reach agreement on such amount within
sixty (60) days after the date EGAT gives the Generator notice of
termination, the inability to reach agreement on such amount shall
be treated as a dispute and subject to resolution in accordance
with Section 15.
14.7 RECONSTRUCTION
If damage to the Facility by Force Majeure after the Commercial Operation
Date of the First Unit renders the Facility substantially incapable of
generating electricity, the Parties shall determine (or in the absence of
agreement by the Parties an Expert shall determine in accordance with
Section 15) whether within thirty (30) months from the date such damage
occurred, the Facility can be restored to a condition such that (i) the
Dependable Contracted Capacity established for each Unit immediately
following restoration would be at least ninety percent (90%) of its
Contracted Capacity, and (ii) the Availability of each Unit over the six
(6) months immediately following restoration would exceed seventy-five
percent (75%) of its Actual Availability over the six (6) months
immediately preceding the Force Majeure.
If it is determined that the Facility can be restored to such a condition
within thirty (30) months or less from the date such damage occurred, this
Agreement may not be terminated under Section 14.6.1, 14.6.3 or 14.6.4 and
the Generator shall commence
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restoration of the Facility. Notwithstanding the foregoing, the Generator
shall not be required to commence such restoration and this Agreement may
be terminated immediately by either Party if, within a reasonable period of
time from the date such damage occurred, either (i) the Generator cannot
obtain any approval required by the Financing Parties for such restoration,
or (ii) the Generator cannot arrange any additional funding required for
such restoration on commercially reasonable limited recourse financing
terms.
If it is determined that the Facility cannot be restored to the condition
described above within thirty (30) months from the date such damage to the
Facility occurred, or if the Generator is not required to commence
restoration under circumstances referred to in the preceding paragraph,
this Agreement may be terminated immediately by either Party and the
provisions of Section 14.6.1, 14.6.3 or 14.6.4 shall apply.
15. DISPUTE RESOLUTION
15.1 RESOLUTION
15.1.1 The Parties agree to make a diligent, good faith attempt to resolve
all disputes arising under or in connection with this Agreement in
an equitable manner and in accordance with procedures to be agreed
upon before either Party commences dispute resolution by Experts or
arbitration. This attempt shall involve discussions between
designated representatives of each Party, and then, if such
representatives are unable to resolve the dispute pursuant to this
Section 15.1.1 within ninety (90) days, the Parties shall appoint
an independent Expert or commence an arbitration in accordance with
Section 15.1.2 or 15.2.
15.1.2 If such dispute involves in whole or in part (i) a technical
engineering issue, then the Parties will in good faith attempt to
appoint a suitably experienced and qualified independent
engineering firm reasonably satisfactory to both of them, (ii) a
financial issue, then the Parties will in good faith attempt to
appoint a financial advisor or investment bank reasonably
satisfactory to both of them, or (iii) any other issue with respect
to which referral to an Expert is provided hereunder, then the
Parties will in good faith attempt to appoint an Expert with
appropriate expertise for the subject matter reasonably
satisfactory to both of them, in each case to act in relation to
such dispute and to render a final and binding determination in
respect thereof. Absent fraud or wilful misconduct in respect of an
Expert's determination, the Parties hereby waive any rights to
appeal or review of such determination by any court or tribunal.
The Parties shall share the cost of the Expert equally.
15.2 ARBITRATION
15.2.1 If the dispute involves any type of issue not otherwise addressed
in Section 15.1.2, or if the Parties are unable to agree upon an
acceptable Expert pursuant to Section 15.1.2, or if the Expert does
not render a decision within thirty (30) days after completion of
the hearing of the matter or if the dispute is not resolved by the
Expert within one hundred and fifty (150) days after the referral
to the Expert, then either Party may commence arbitration ten (10)
days after giving notice to the other Party. Nothing herein shall
prevent a Party from commencing arbitration at any time (i) when
the delay required for performance hereunder might materially and
adversely affect such Party's interest, or (ii) when the other
Party fails to fulfill its obligations under this Section 15.
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15.2.2 The arbitration shall be conducted in accordance with the Rules of
Arbitration and Conciliation of the International Chamber of
Commerce as in effect at the time of the arbitration or as
otherwise agreed upon by the Parties (the RULES).
15.2.3 The arbitral tribunal shall consist of three (3) arbitrators. Each
Party shall appoint one arbitrator with, in the case of a dispute
of a technical nature, knowledge and experience in such technical
matters. The two arbitrators so appointed shall appoint the third
arbitrator who shall serve as the chairman of the arbitral
tribunal. If a Party fails to appoint its arbitrator within a
period of ten (10) days after receiving notice of the arbitration,
or if the two arbitrators appointed cannot agree upon the third
arbitrator within a period of ten (10) days after appointment of
the second arbitrator, then such arbitrator shall be appointed
pursuant to the Rules.
15.2.4 If the Court of Arbitration of the International Chamber of
Commerce is required or requested to appoint an arbitrator, it
shall appoint only a person with experience in international
commercial agreements and, in particular, the implementation and
interpretation of contracts relating to the design, engineering,
construction, operation and maintenance of electrical power
generating facilities (and if the dispute concerns a technical
issue, a person who has knowledge and experience in technical
matters). No arbitrator shall be a present or former employee or
agent of, or consultant or counsel to, either Party or any
Affiliate thereof or any Governmental Authority.
15.2.5 The arbitration shall be conducted in Thailand using the English
language unless the use of the Thai language is agreed upon by the
Parties. All documents or evidence presented at such arbitration in
a language other than in English shall be accompanied by a
certified English translation thereof. The arbitrators shall decide
the dispute by majority of the arbitral tribunal and shall state in
writing the reasons for its decision. Any monetary award of the
arbitral tribunal shall be denominated and payable in Baht.
15.2.6 Any decision or award of an arbitral tribunal appointed pursuant to
Section 15 shall be final and binding upon the Parties. The Parties
hereby waive any rights to appeal or seek review of such a decision
or award by any court or tribunal, excluding any statutory defenses
or rights of appeal in enforcement proceedings under the
Arbitration Act of Thailand (B.E. 2530, or as it may be amended
after the Execution Date) that cannot legally be waived. The
Parties further undertake to carry out without delay the provisions
of any arbitral award or decision, and each agrees that any such
award or decision, may be enforced by the Parties against assets of
the relevant Party wherever they are located and a judgment upon
any arbitration award may be entered by any court or tribunal
having jurisdiction. Subject to Section 21, either Party may
publicize or otherwise disclose to others the contents of any
decision of the arbitral tribunal.
15.2.7 The costs of such arbitration shall be determined and allocated
between the Parties by the arbitral tribunal in its award.
15.2.8 Unless otherwise agreed in writing, the Parties shall continue to
perform their respective obligations under this Agreement during
the pendency of any proceeding by the Parties in accordance with
this Section 15.
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15.2.9 The provisions of Section 15.2 shall survive the termination of
this Agreement until all obligations which are intended to survive
termination have expired.
16. LIMITATION OF LIABILITY
16.1 INDEMNIFICATION
16.1.1 Except as otherwise specifically provided in this Agreement, or
unless the damage or injury arises out of, results from, or is
caused by, the breach of this Agreement by a Party or by the
negligence or misconduct of a Party's own officers, directors,
employees, agents, Affiliates, contractors or subcontractors,
neither Party shall be liable to the other for any claims,
judgments, liabilities, losses, costs, expenses or damages of any
kind or character (including loss of use of property) in connection
with damages or destruction of property or personal injury
(including death) arising out of the performance of the Agreement,
including the design, construction, maintenance or operation of
property, facilities or equipment owned or used by the other Party,
or the use of, misuse of or contact with the electrical energy
delivered or purchased hereunder.
16.1.2 Each Party shall indemnify and hold the other Party, and its
officers, directors, Affiliates, agents, employees, contractors and
subcontractors, harmless from and against any and all claims,
judgments, losses, liabilities, costs, expenses (including
reasonable attorneys' fees) and damages of any nature whatsoever
for personal injury, death or property damage (except workers'
compensation claims) caused by any act or omission of the
indemnifying Party or the indemnifying Party's own officers,
directors, Affiliates, agents, employees, contractors or
subcontractors that arises out of or are in any manner connected
with the performance of this Agreement, except to the extent such
injury, death or damage is attributable to the negligence or
misconduct of, or breach of this Agreement by, the Party or its
officers, directors, Affiliates, agents, employees, contractors or
subcontractors seeking indemnification hereunder.
16.1.3 The Generator shall defend, indemnify and hold EGAT, and its
officers, directors, Affiliates, agents, employees, contractors and
subcontractors, harmless from and against any and all claims,
judgments, liabilities, losses, costs, expenses (including
reasonable attorneys' fees) and damages (i) under every applicable
environmental law or regulation arising out of the condition of the
Site, the Generator's ownership or operation of the Facility, or
the Generator's construction of the New Transmission Facilities,
including the discharge, dispersal, release, storage, treatment,
generation, disposal or escape of pollutants or other toxic or
hazardous substances from the Facility, the contamination of the
soil, air, surface water or groundwater at or around the Site or
any pollution abatement, replacement, removal, or other
decontamination or monitoring obligations with respect thereto, and
(ii) under any Law arising out of the Generator's construction,
testing or commissioning of the New Transmission Facilities, except
to the extent such damages under this Section 16.1.3 are
attributable to the negligence or misconduct of, or breach of this
Agreement by EGAT, its officers, directors, Affiliates, agents
employees, contractors or subcontractors.
16.1.4 EGAT shall defend, indemnify, and hold the Generator, its officers,
directors, Affiliates, agents, employees, contractors, and
subcontractors, harmless from
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and against any and all claims, judgments, liabilities, losses,
costs, expenses (including reasonable attorneys' fees), and damages
under every applicable environmental law or regulation arising out
of the condition of or EGAT's ownership or operation of the New
Main Transmission Line, and the New Transmission Facilities and
EGAT's Connection (after their transfer to EGAT pursuant to Section
2.8.6), including the discharge, dispersal, release, storage,
treatment, generation, disposal, or escape of pollutants or other
toxic or hazardous substances from any of such facilities, the
contamination of the soil, air, surface water or groundwater at or
around any of such facilities or any pollution abatement,
replacement, removal, or other decontamination or monitoring
obligations with respect thereto, except to the extent such damages
are attributable to the negligence or misconduct of, or breach of
this Agreement by the Generator, its officers, directors,
Affiliates, agents, employees, contractors, or subcontractors.
16.1.5 In no case shall EGAT be liable for damage or destruction of
property, facilities or equipment operated by the Generator solely
as a result of EGAT's Dispatch or the Generator's operation of the
Facility, provided such Dispatch by EGAT was in accordance with the
terms of this Agreement and the Grid Code.
16.2 CONSEQUENTIAL DAMAGES
Neither Party shall be liable to the other Party for any indirect,
incidental, consequential or punitive damages as a result of the
performance or non-performance of the obligations imposed pursuant to this
Agreement, including failure to deliver or purchase electrical energy
hereunder, irrespective of the causes thereof, including fault or
negligence. For the avoidance of doubt, (i) neither the Generator's
Minimum Take Liability under the Fuel Purchase Agreement nor reasonable
termination costs under the Financing Documents shall be regarded as
indirect, incidental, consequential or punitive damages, and (ii) the
indemnification provisions set out in Section 16.1 shall not be construed
as giving indemnity against indirect, incidental, consequential or punitive
damages.
17. CHANGE-IN-LAW
17.1 TAX CHANGE ADJUSTMENT
On or before the fifth (5th) Business Day after the close of each quarter
in any calendar year following the Execution Date the Generator shall (i)
determine the amount of any increase or reduction in Taxes (excluding
corporate income or similar taxes imposed on or measured by the overall net
income of, but only to the extent generally applicable to, Persons doing
business in Thailand) paid or payable by the Generator in respect of the
Project for the preceding three Billing Periods resulting from any Change-
in-Law (or the previous three months if such Change-in-Law occurs prior to
the Commercial Operation Date of the First Unit), and (ii) submit to EGAT a
certificate setting forth in detail reasonably satisfactory to EGAT the
basis of and the calculations for such amount of increase or reduction,
including a description of the spare parts purchased by the Generator
during such period if the Generator is seeking compensation under this
Section 17.1 for Taxes paid or payable on such spare parts. EGAT and the
Generator shall promptly determine, in good faith, any necessary
adjustments to the Availability Payments or the Energy Payments to
equitably reflect any such increase or reduction in Taxes with the intent
that the financial position of the Generator shall not be affected in any
material respect by such Change-in-Law, provided that the Generator shall
not be
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entitled to receive interest on any previously paid or incurred cost
except to the extent that the adjustment required under this Section 17.1
shall be delayed due to the negligence of EGAT. Each Party shall cooperate
in good faith with the other Party in connection with any such
determination. Thereafter, the Availability Payments or the Energy
Payments and such other payments (if applicable) shall be adjusted to
reflect such increase or reduction and applied in the formulae set out in
Schedules 2 and 3.
17.2 CHANGE-IN-LAW ADJUSTMENT
17.2.1 If there is a Change-in-Law which requires the Generator to make
any material capital improvement or other material modification to
the Facility in order to comply with any Law, the Generator shall
submit to EGAT a certificate setting forth in detail reasonably
satisfactory to EGAT the costs of such capital improvement or other
modification, including financing costs, if any, related thereto.
EGAT and the Generator shall promptly determine as set out below,
in good faith, any necessary adjustments to the Availability
Payments to equitably compensate the Generator for such costs. Each
Party shall cooperate in good faith with the other Party in
connection with any such determination.
For the purposes of this Section 17.2.1, a material capital
improvement or other material modification to the Facility shall
mean one or more capital improvements or other modifications having
an aggregate cost in excess of twenty million (20,000,000) Baht for
any calendar year. In determining whether such aggregate cost
exceeds twenty million (20,000,000) Baht for any calendar year, the
amount representing the total cost of any capital improvement or
other modification (after any reduction made to such amount
pursuant to Section 17.2.4) shall be deemed to be expended on the
date in the calendar year on which the Change-in-Law becomes
effective. If such aggregate cost exceeds twenty million
(20,000,000) Baht for any calendar year, the Availability Payments
shall be adjusted to reimburse the Generator the portion of such
aggregate cost in excess of twenty million (20,000,000) Baht.
17.2.2 If there is a Change-in-Law (other than in respect of Taxes) which
the Generator believes in good faith will materially increase the
costs or materially decrease the revenues of the Generator in
connection with the financing, construction, operation or
maintenance of the Facility, then the Generator shall submit to
EGAT a certificate setting forth in detail reasonably satisfactory
to EGAT the basis of and the calculations for the amount of such
increase in costs or decrease in revenues. EGAT and the Generator
shall promptly determine, in good faith, any necessary adjustments
to the Availability Payments or the Energy Payments to equitably
reflect such increase in costs or decrease in revenues with the
intent that the financial position of the Generator shall not be
affected by such Change-in-Law. Each Party shall cooperate in good
faith with the other Party in connection with any such
determination. For the purposes of this Section 17.2.2, a material
increase in costs or material decrease in revenues means any one or
more Change-in-Law events resulting in an increase in costs and/or
decrease in revenues in excess of five million (5,000,000) Baht for
any calendar year.
17.2.3 If there is a Change-in-Law (other than in respect of Taxes) which
EGAT believes in good faith will materially decrease the costs or
materially increase the revenues of the Generator in connection
with the financing, construction, operation or maintenance of the
Facility, then EGAT shall submit to the
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Generator a certificate setting forth in detail reasonably
satisfactory to the Generator the basis of and the calculations for
the amount of such decrease in costs or increase in revenues. EGAT
and the Generator shall promptly determine, in good faith, any
necessary adjustments to the Availability Payments or the Energy
Payments to equitably reflect such decrease in costs or increase in
revenues with the intent that the financial position of the
Generator shall not be affected by such Change-in-Law. Each Party
shall cooperate in good faith with the other Party in connection
with any such determination. For the purposes of this Section
17.2.3 a material decrease in costs or material increase in
revenues means any one or more Change-in-Law events resulting in a
decrease in costs or increase in revenues in excess of five million
(5,000,000) Baht for any calendar year.
17.2.4 As soon as practicable after the Generator becomes aware of any
Change-in-Law which could reasonably be expected to give rise to an
adjustment pursuant to Section 17.2.1 or 17.2.2, the Generator
shall notify EGAT of the Change-in-Law and the expected effect on
the costs and revenues of the Generator. After the Generator
determines that it will be required to make any additional
operating or capital expenditures for which the Generator may be
entitled to an adjustment to the Availability Payments or the
Energy Payments pursuant to Section 17.2.1 or 17.2.2, the Generator
shall consult with EGAT regarding such expenditures and Generator
shall use all reasonable efforts to implement EGAT's
recommendations, if any, to minimize such expenditures consistent
with Prudent Utility Practices and the Generator's obligations
under this Agreement.
If the Generator makes any such capital expenditure without so
consulting with EGAT, the amount treated as the cost of the capital
improvement or modification to the Facility for purposes of Section
17.2.1 shall be limited to the cost of EGAT's reasonably determined
proposal for such improvement or modification to accommodate the
Change-in-Law. In the event the Generator initiates consultation
with EGAT and (i) EGAT objects to the Generator's proposed
expenditure as not being the lowest cost option within a reasonable
period of time, and (ii) EGAT demonstrates that there is a lower-
cost alternative that complies with the Change-in-Law which is
consistent with Prudent Utility Practices and will not adversely
affect the costs or manner of operations or maintenance and
economic life of the Facility, then the amount treated as the cost
of the capital improvement or modification to the Facility for
purposes of Section 17.2.1 shall be the cost of the alternative
demonstrated by EGAT.
17.2.5 For purposes of this Section 17.2, a change in Grid Code shall be
treated as a Change-in-Law.
17.2.6 If a change in an environmental Law requires the Generator to meet
a standard which exceeds a standard set out in Schedule 8, the
costs attributable to making the Facility or the operation thereof
meet such standard shall be subject to reimbursement in accordance
with the Section 17.2.1 or 17.2.2, provided that the Generator
shall not be entitled to any reimbursement under Section 17.2.1 or
17.2.2 for any portion of such costs which are attributable to
making the Facility or the operation thereof comply with any
standard set out in Schedule 8.
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17.3 BOI PRIVILEGES
17.3.1 EGAT acknowledges that the Availability Payments contemplated to be
paid to the Generator pursuant to this Agreement have been
determined based on the assumption that the Generator shall have
received certain investment promotion and tax incentives pursuant
to the Thailand Office of the Board of Investment Announcement No.
1/1993 on Policies and Criteria for Investment Promotion, Board of
Investment Announcement No. 2/1993 on List of Activities Eligible
for Investment Promotion and Board of Investment Announcement No.
2/1995 on Provision of Support for Power Generation Activity to be
Developed by Independent Power Producers.
17.3.2 If the Thailand Office of the Board of Investment (other than due
to an act or omission of the Generator) fails to grant the
Generator the investment promotion and tax incentives referred to
in Section 17.3.1 at the same tax rates and for the same exemption
or incentive periods contemplated under the Board of Investment
Announcements described in Section 17.3.1, or subsequent to the
granting thereof a Change-in-Law reduces the investment promotion
and tax incentives first granted, the Generator may request from
EGAT an equitable adjustment in the Availability Payments. Any
request by the Generator for such an equitable adjustment shall
include a certificate setting forth in details reasonably
satisfactory to EGAT the increased costs, expenses, Taxes,
decreased revenues and reduced return on equity resulting from such
failure to obtain or such subsequent reduction in any such
investment promotion and tax incentives. To the extent necessary,
the Parties shall promptly determine, in good faith, any necessary
adjustments to the Availability Payments or Energy Payments to
equitably reflect the impact of such failure to obtain or such
subsequent reduction in the investment promotion and tax incentives
with the intent that the financial position of the Generator shall
not be affected.
18. CONFIRMATION STATEMENT
18.1 CONFIRMATION OF AVAILABILITY AND METERED ENERGY
The Generator shall prepare and submit to EGAT a daily Confirmation
Statement no later than three (3) Business Days after the day to which it
relates. In addition, the Generator shall prepare and submit to EGAT a
Meter Reconciliation Statement following the annual meter test or any other
meter test conducted pursuant to Section 2.4.3. The Meter Reconciliation
Statement shall set out the results of any such test and any adjustments to
be made or other action to be taken following the test.
18.2 ACCESS TO INFORMATION
If available, the Generator shall provide such information as EGAT may
reasonably request to verify a Confirmation Statement provided that such
information is not readily available to EGAT by any other means.
18.3 REVIEW OF CONFIRMATION STATEMENT AND METER RECONCILIATION STATEMENT
EGAT shall review the Confirmation Statement and any Meter Reconciliation
Statement. Each Party shall notify the other Party in writing as soon as
practicable, and in any event within fourteen (14) Business Days after
having received the Confirmation Statement or Meter Reconciliation
Statement of any errors or omissions which the
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reviewing Party believes should be corrected. Subject to any alleged errors
or omissions notified by the reviewing Party to the other Party in writing
pursuant to this Section 18.3, the information contained in a Confirmation
Statement or Meter Reconciliation Statement shall, save in the case of
fraud or manifest error and subject to Section 18.6, be deemed to have been
approved by both Parties on the fifteenth (15th) Business Day after the
Confirmation Statement or Meter Reconciliation Statement shall have been
received.
18.4 DISPUTES
If the Parties cannot agree on whether any information contained in a
Confirmation Statement or Meter Reconciliation Statement is complete or
correct within fourteen (14) Business Days after the Confirmation Statement
or Meter Reconciliation Statement was received, the dispute shall be
referred to an Expert for determination in accordance with Section 15.1.2
or settled by arbitration in the circumstances in which arbitration is
provided under Section 15.2.1.
18.5 FINAL CONFIRMATION STATEMENT
Any Confirmation Statement which has been approved by both Parties, or
deemed to have been approved in accordance with Section 18.3, or which is
approved by a final decision of an Expert or arbitration, shall be a final
confirmation statement (FINAL CONFIRMATION STATEMENT). The information
contained in a Final Confirmation Statement shall be binding on both
Parties for the purposes of this Agreement save in the following
circumstances:
(a) (other than in the case of a determination by an Expert or by
arbitration) in the case of misrepresentation and subject to Section
18.6; or
(b) in the event of any adjustment pursuant to Section 18.8.
18.6 DISPUTES LIMITATION
Nothing in this Section 18 shall prevent either Party from disputing the
information contained in or referred to in a Confirmation Statement or
Meter Reconciliation Statement at any time where it is reasonable under all
the circumstances so to do, provided that no dispute shall be raised in
relation to information regarding a Settlement Period after the first
anniversary of the day during which such Settlement Period occurred.
18.7 EFFECT OF CONFIRMATION STATEMENT
The Final Confirmation Statement (or pending resolution of any outstanding
disputes, the Confirmation Statement) shall be used by the Generator to
prepare Payment Invoices/Credit Notes as required by Section 19.
18.8 ENERGY PAYMENT ADJUSTMENTS
18.8.1 Where a Meter Reconciliation Statement shows that an adjustment in
the amount due is required and the meter inaccuracy cannot be
attributed to a particular Settlement Period, the adjustment (in
MWh) shown in such Meter Reconciliation Statement shall be
converted by a monetary adjustment factor
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(MA) at a rate (in Baht/MWh) calculated in accordance with the
following formula:
MA = y/x
where:
x = the total metered Net Electrical Generation at the Metering
Point for the relevant quarterly period as shown
(unadjusted) in such Meter Reconciliation Statement;
y = the total amount paid as components of the Energy Payments
(calculated by reference to the terms FCharge//x// and
VCharge//x// in the equations in Schedule 3) in respect of
such metered Net Electrical Generation in the relevant
quarterly period (determined on the basis of such terms).
18.8.2 For the avoidance of doubt, where a Meter Reconciliation Statement
shows that an adjustment is required and the meter inaccuracy can
be attributed to a particular Settlement Period, the number of MWh
delivered in that Settlement Period shall be so adjusted and the
adjustment payments shall be made to or by the Generator as
appropriate.
18.9 INTERFERENCE WITH METERING
If either Party shall interfere with Metering in a manner which gives rise
to a need for a meter adjustment necessitating an additional payment or
rebate to the other Party, such payment shall be made or rebate paid
together with interest thereon at the Default Rate for the period for which
such payment or rebate is outstanding.
19. BILLING AND PAYMENT
19.1 PAYMENT INVOICE/CREDIT NOTE
The Generator shall prepare and issue to EGAT a Payment Invoice/Credit Note
in the form set out in Schedule 6 within three (3) Business Days after the
completion of all Final Confirmation Statements for the Billing Period. If
there is a dispute over a Confirmation Statement, the Generator may, from
the fifteenth (15th) Business Day after it is received by EGAT, treat that
Confirmation Statement as a Final Confirmation Statement for the purposes
of preparing the Payment Invoice/Credit Note for the applicable Billing
Period.
Such Payment Invoice/Credit Note shall set out either (i) the net amount of
the Availability Payments due to the Generator from EGAT for that month (if
the aggregate amount of the Availability Payments exceeds the aggregate
amount of the deductions from Availability Payments for that month), or
(ii) the net amount of the rebate due to EGAT from the Generator for that
month (if the aggregate amount of the Availability Payments is less than
the aggregate amount of the deductions from Availability Payments for that
month). The Payment Invoice/Credit Note shall reflect any adjustments of
invoice or credit amounts required by any Meter Reconciliation Statement in
accordance with Sections 2.4.4 and 18.1.
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The Generator shall calculate in accordance with paragraph 4.1.2 of
Schedule 2 of this Agreement the adjustment, if any, required to be made in
respect of the difference between (a) the Baht/US$ exchange rate used by
the Generator in the preparation of such Payment Invoice in accordance with
paragraph 4.1 of Schedule 2 of this Agreement and (b) the Baht/US$ exchange
rate applicable on the date of payment by EGAT of such Payment Invoice
(such adjustment, the FX ADJUSTMENT). The Generator shall issue an
adjustment invoice or credit note to EGAT, as applicable, setting forth in
sufficient detail the calculation of the FX Adjustment within five (5)
Business Days after the date of payment by EGAT of each Payment Invoice.
EGAT shall pay the amount shown on any FX adjustment invoice within thirty
(30) days after receipt of such invoice. Any FX Adjustment credit note
issued by the Generator shall be taken into account in the first Payment
Invoice prepared following the issuance of such credit note, provided,
however, that the Generator shall pay the amount set forth in any FX
Adjustment credit note to EGAT in cash or cash equivalent in accordance
with Section 19.3 in the event that such Payment Invoice has not been
prepared and submitted to EGAT for any reason within thirty (30) days of
when otherwise required to be submitted to EGAT in accordance with this
Agreement. Neither Party shall be liable for interest in respect of the FX
Adjustment for the period before the date payment or credit of the FX
Adjustment is due. The FX Adjustment shall not be subject to adjustment
pursuant to Paragraph 4.1 of Schedule 2 of this Agreement.
The undisputed amount shown in the Payment Invoice/Credit Note as payable
by EGAT or the Generator shall be paid within thirty (30) days after
receipt of such invoice or issuing of such credit note.
19.2 OTHER PAYMENTS
Except where expressly provided to the contrary any payment to be made by
either Party under this Agreement shall be made within thirty (30) days
after the Party liable to make payment receives a demand from the other
Party for the same.
19.3 PAYMENT PROCEDURE
Any sums payable pursuant to this Agreement shall be made by check or by
the deposit of funds by wire transfer into a Thai bank account as may be
notified by the receiving Party to the paying Party in writing from time to
time or by such other means as the Parties may agree. Bank charges will be
the receiving Party's expense. Each Party shall notify the other of the
details of the bank account to which sums due to that Party shall be
credited, identifying such bank account by means of the bank sort code
number, the bank account number and bank account title. Any payment that
becomes due and payable on a day that is other than a Business Day shall be
paid on the first (1st) Business Day thereafter.
19.4 APPLICATION OF PAYMENTS
Any payments received by one Party from the other under this Agreement
shall be applied in or towards settlement of amounts payable to the
recipient, with the longest outstanding amount being settled first,
provided that this Section 19.4 shall not apply in respect of any amount
which is disputed in good faith in accordance with this Agreement.
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19.5 INTEREST
Any amount (other than one which is disputed in good faith in accordance
with this Agreement) determined to be properly due from one Party to the
other pursuant to this Agreement and remaining unpaid after the due date
for payment shall bear interest at the Default Rate from and including the
due date as so determined until but excluding the date that it is received
by the Party entitled to it. Interest shall accrue at the Default Rate on
a day to day basis and shall be compounded monthly.
19.6 DISPUTED ITEMS
If any sum or part of a sum shown on an invoice submitted by one Party is
disputed in good faith by the other Party, and it is subsequently
determined in accordance with the dispute resolution provisions set out in
Section 15 that any amount withheld by the other Party should have been
properly payable to the Party submitting such invoice, the other Party
shall pay to the Party submitting such invoice interest in respect of such
disputed amount at the Default Rate from and including the date that the
amount in question was due up to but excluding the date on which the Party
submitting such invoice receives payment. The undisputed amount of each
invoice shall be paid promptly notwithstanding a dispute about any other
amount invoiced.
If any sum or part of a sum shown on an invoice submitted by one Party is
paid but is subsequently disputed or questioned, and is subsequently agreed
or determined not to have been properly payable, then such Party shall
refund the amount which was not properly payable together with interest at
the Default Rate from and including the date of receipt up to but excluding
the date of repayment. Whenever any payment or refund is required to be
made upon resolution of any dispute under this Section 19.6, appropriate
adjustments in respect of VAT shall be made by the Parties including the
issuing of credit notes, invoices (receipted or otherwise) and the payment
of VAT or further sum of VAT. Any dispute pursuant to the provisions of
this Section 19.6 shall be referred to an Expert for determination in
accordance with Section 15.1.2.
19.7 TAXES AND FINES
19.7.1 Taxes and Fees
The Generator shall pay when due all present and future Taxes
(whether national or local) imposed in connection with the
ownership, operation and maintenance of the Facility, and shall pay
all other duties, assignments, levies, fees, costs and expenses of
any kind (whether or not to a Governmental Authority) necessary to
assure the performance of its obligations under this Agreement,
except as otherwise provided in Section 12.3 or below. EGAT shall
pay when due all present and future (whether national or local) VAT
imposed on the sale to EGAT and purchase by EGAT of electricity
under this Agreement. It is expressly understood that each Party
shall be separately responsible for all Taxes imposed on its
overall net income.
19.7.2 Fines
Any fines, penalties or other costs incurred by the Generator or
its agents, officers, directors, employees, Affiliates, contractors
or subcontractors for non-compliance by the Generator, its agents,
officers, directors, employees, Affiliates, contractors or
subcontractors with the requirements of any Laws or
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Governmental Approvals shall not be reimbursed by EGAT but shall be
the sole responsibility of the Generator.
If any fines, penalties or other costs are assessed against EGAT or
its agents, officers, directors, employees, Affiliates, contractors
or subcontractors by any Governmental Authority due to the non-
compliance by the Generator with any Laws, the Grid Code or
Governmental Approvals, the Generator shall indemnify and hold
harmless EGAT against any and all losses, liabilities, damages and
claims suffered or incurred because of the failure of the Generator
to comply therewith. The Generator shall also reimburse EGAT for
any and all legal or other expenses (including attorneys' fees and
expenses) reasonably incurred by EGAT in connection with such
losses, liabilities, damages and claims.
If any fines, penalties or other costs are assessed against the
Generator or its agents, officers, directors, employees,
Affiliates, contractors or subcontractors by any Governmental
Authority due to the non-compliance by EGAT with any Laws, the Grid
Code or Governmental Approvals, EGAT shall indemnify and hold
harmless the Generator against any and all losses, liabilities,
damages and claims suffered or incurred because of the failure of
EGAT to comply therewith. EGAT shall also reimburse the Generator
for any and all legal or other expenses (including attorneys' fees
and expenses) reasonably incurred by the Generator in connection
with such losses, liabilities, damages and claims.
19.8 SET-OFF
All payments to be made by either Party under this Agreement shall be made
without set-off, counterclaim, withholding or deduction, including any set-
off, counterclaim, withholding or deduction for or on account of Taxes,
except as expressly provided in this Agreement or required by applicable
Law.
20. INDEXATION
20.1 If any index or external price reference for a particular date or period is
not available when required for the purposes of this Agreement, the Parties
shall seek to agree to use such other index or price reference for such
dates or periods as shall be appropriate in the circumstances.
20.2 If any index or external price reference referred to in this Agreement
ceases to be published or if the basis on which it is calculated is
materially altered, the Parties shall seek to agree to use such other index
or price reference as shall be appropriate in the circumstances.
20.3 Any dispute under Section 20.1 or 20.2 that cannot be resolved by agreement
within fourteen (14) days after the dispute arises shall be referred to an
Expert for determination in accordance with Section 15.
20.4 This Section 20 is without prejudice to any other provision of this
Agreement which provides for periodic review of any indexes or external
price references which are used for the purposes of this Agreement.
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21. CONFIDENTIALITY AND ANNOUNCEMENTS
21.1 GENERAL RESTRICTIONS ON THE PARTIES
Neither Party shall at any time, whether before or after the expiration or
earlier termination of this Agreement, divulge or suffer or permit its
officers, directors, employees, Affiliates, agents, contractors or
subcontractors to divulge to any other person any confidential information
relating to this Agreement or any other information labeled "CONFIDENTIAL"
which may be provided to such Party (the RECEIVING PARTY) by the other
Party pursuant to this Agreement or the Grid Code, or in the course of
negotiating this Agreement or otherwise concerning the operations,
contracts, commercial or financial arrangements or affairs of the other
Party except:
(a) in the circumstances set out in Section 21.2;
(b) to the extent otherwise expressly permitted by this Agreement; or
(c) with the prior consent of the other Party.
21.2 EXCEPTIONS
The restrictions imposed by Section 21.1 shall not apply to the disclosure
of any information:
(a) which now or hereafter comes into the public domain other than as a
result of a breach of an undertaking of confidentiality;
(b) which is required to be disclosed in compliance with the conditions of
any licenses or any document referred to in any such license with
which the Receiving Party is required to comply;
(c) which is required to be disclosed by any other requirement of Law or
Government Authority;
(d) required by any court, arbitrator or administrative tribunal or the
Expert in the course of proceedings before it to which the Receiving
Party is a party, provided that such parties, to the extent permitted
by applicable laws, shall be bound by the provisions contained in this
Section;
(e) to the employees, directors, Affiliates, agents, proposed assignees,
consultants or professional advisors of the Receiving Party, in each
case on the basis set out in Section 21.3, provided that such parties
shall be bound by the provisions contained in this Section 21;
(f) to the Financing Parties or insurers or their respective consultants
and advisors, provided that the Receiving Party agrees to keep such
information confidential on terms no less onerous than those set out
in Section 21.1; and
(g) as may be required to comply with the Grid Code.
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21.3 INTERNAL PROCEDURES
With effect from the date of this Agreement each Party shall adopt
procedures within its organization for ensuring the confidentiality of all
information which it is obligated to preserve as confidential under Section
21.1. Those procedures shall be as follows:
21.3.1 The confidential information will be disseminated within the
Receiving Party only to persons who need such information to carry
out the functions which they are employed to carry out.
21.3.2 The confidential information shall not be used by the Receiving
Party for the purpose of obtaining for such Party or any Affiliate
thereof or for any other Person any contract or arrangement for the
supply of electricity to any Person without the prior consent of
the originator of such confidential information.
21.3.3 Employees, directors, Affiliates, agents, proposed assignees,
consultants and professional advisors of the Receiving Party will
be made fully aware of such Party's obligations of confidence in
relation to confidential information and such Party will be
responsible for any failure by such Persons to comply with such
obligations as if they were parties to this Agreement.
21.3.4 Any copies of the confidential information, whether in hard copy or
computerized form, shall clearly identify the confidential
information as confidential.
21.4 PUBLIC ANNOUNCEMENTS
21.4.1 Subject to Section 21.4.2, no public announcement or statement
regarding the signature, performance or termination of this
Agreement shall be issued or made unless both Parties shall have
been furnished with a copy of the proposed announcement or
statement and shall have approved it (such approval not to be
unreasonably withheld or delayed).
21.4.2 Neither Party shall be prohibited from issuing or making any public
announcement or statement which is required to be made to comply
with any applicable Law or the regulations of any recognized stock
exchange upon which the share capital of such Party (or any parent
company of such Party) is from time to time listed or dealt in or
in response to a requirement of Governmental Authority.
22. INSURANCE AND INDEMNITIES
22.1 INSURANCE REQUIRED
The Generator shall fully apprise EGAT of the insurance requirements
proposed by the Financing Parties (including draft documentation thereon)
and the Generator shall use reasonable efforts to implement recommendations
on such requirements reasonably made by EGAT. The Generator shall obtain
and maintain in effect such insurance policies and coverage as is required
by Law, the Financing Documents and Prudent Utility Practices, including:
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(a) "Comprehensive or Commercial General Liability" insurance with
combined single limits for bodily injury and property damages in
amounts per occurrence and in the aggregate as required by the law of
Thailand;
(b) "Workers' Compensation" insurance that complies with the laws of
Thailand;
(c) "Comprehensive Automobile Liability" insurance with combined single
limits for bodily injury and property damage in amounts per occurrence
and in the aggregate covering vehicles owned, borrowed or hired;
(d) "All Risks Property Coverage" insurance and "Boiler and Machinery"
insurance against damage to the Facility (on a "replacement cost"
basis) in amounts and subject to deductibles in accordance with this
Section 22.1;
(e) "Excess Liability" insurance with a limit per occurrence and in the
aggregate in an amount to be in excess of the limits of insurance
provided in subsections (a) and (c) above; and
(f) "Business Interruption" insurance in amounts and subject to
deductibles in accordance with this Section 22.1.
The Generator shall maintain throughout the Term of this Agreement the
scope and type of insurance coverage (other than "Business Interruption"
insurance) as is initially required to be obtained and maintained by the
Financing Documents, provided the types of insurance and the amount thereof
are reasonably acceptable to EGAT. The Generator shall not reduce the
scope of such insurance without the prior written consent of EGAT, such
consent not to be unreasonably withheld or delayed.
22.2 ENDORSEMENTS
The Generator shall cause its insurers to amend its Comprehensive or
Commercial General Liability Policy and, if applicable, any Excess
Liability Policy and All Risks Property Coverage with the following
endorsement items (a), (b) and (c), and to amend its Workers' Compensation
and Automobile Liability policies with endorsement item (c):
(a) EGAT and its officers, directors, employees and agents are additional
insureds under the policy;
(b) the insurer waives all rights of subrogation against EGAT, its
officers, directors, employees and agents; and
(c) notwithstanding any provision of the policy, the policy may not be
cancelled, non-renewed or materially changed without the insurer
giving thirty (30) days' prior written notice to EGAT. All other
terms and conditions of the policy remain unchanged.
22.3 CERTIFICATES REQUIRED
At least sixty (60) days prior to the date set for the commencement of
construction and annually upon renewal or otherwise in accordance with the
terms of the relevant insurance policies, the Generator shall provide for
EGAT's review and approval evidence of the insurance required by Section
22.1 in a form acceptable to EGAT. The
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Generator shall also provide EGAT with copies of the receipts appropriate
to the annual premiums in respect of the insurance coverages and
endorsements.
Failure of the Generator to obtain the insurance coverages required by this
Section 22 or to provide EGAT with the certificates or copies of receipts,
shall in no way relieve the Generator of the insurance requirements of this
Section 22 or limit the Generator's obligations and liabilities under any
provision of this Agreement.
22.4 APPLICATION OF PROCEEDS
For the Term of this Agreement, and subject to the requirements of the
Financing Documents and any rights or remedies thereunder, the Generator
shall apply any and all insurance proceeds received in connection with any
damage to the Facility toward the repair, reconstruction or replacement of
the Facility.
23. REPRESENTATIONS AND WARRANTIES
23.1 The Generator represents and warrants to EGAT as follows:
(a) The Generator is a corporation duly organized, validly existing and in
good standing under the laws of Thailand and is qualified and in good
standing in each other jurisdiction where the failure so to qualify
would have a material adverse effect upon the business or financial
condition of the Generator or the Facility, and the Generator has all
requisite power and authority to conduct its business, to own its
properties and to execute, deliver and perform its obligations under
this Agreement.
(b) The execution, delivery and performance by the Generator of this
Agreement has been duly authorized by all necessary corporate action,
and does not and will not (i) require any consent or approval of the
Generator's Board of Directors, shareholders or any other third Party,
other than those that have been obtained (evidence of which shall be,
if it has not already been, delivered to EGAT), or (ii) result in a
breach of, or constitute a default under, any provisions of the
Generator's constitution or incorporation documents, any indenture,
contract or agreement to which it is a party or by which it or its
assets may be bound, or violate any law, rule, regulation, order, writ
judgment, injunction, decree, determination or award at present in
effect having applicability to the Generator.
(c) Each Project Agreement constitutes or, when executed will constitute,
a legal, valid and binding obligation of the Generator and is
enforceable by and against the Generator in accordance with its terms.
Upon the exercise of any step in rights under Section 12.3 or the
occurrence of any purchase of the Project by EGAT under Section 14.6,
EGAT shall have the right, but not the obligation to assume the rights
and obligations of the Generator as provided in such Project
Agreements. Moreover, each Project Agreement:
(i) will include no terms or conditions which conflict with the
provisions of this Agreement,
(ii) will not provide that any unsecured creditor of the Generator
shall be given higher priority as a creditor than EGAT, other
than rights which may arise by operation of Law,
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(iii) will include terms and conditions (including the selection of
counterparties and suppliers) that can reasonably be expected
to enable the Project to be successfully completed as
contemplated in this Agreement,
(iv) will include acknowledgments of the counterparties thereto
that, to the extent required to do so in order to give effect
to the purposes of this Agreement, they shall cooperate in the
exercise by the Parties of the step-in and buyout rights and
rights related thereto as provided in this Agreement, such
rights to include the right of EGAT (but not its obligation)
to exercise on behalf of or assume the Generator's rights
under that Project Agreement, and
(v) in the case of the Financing Documents, will include an
acknowledgment by the Financing Parties of the restrictions
contained in Section 25.4 relating to assignment by the
Financing Parties.
(d) No Governmental Approval by any Governmental Authority or pursuant to
any Law as in effect on the date hereof, other than those that have
been obtained, or to be obtained when required, is necessary for the
due execution, delivery and performance by the Generator of this
Agreement.
(e) This Agreement constitutes a legal, valid and binding obligation of
the Generator and is enforceable against the Generator in accordance
with its terms.
(f) There is no pending or, to the best of the Generator's knowledge,
threatened action or proceeding affecting the Generator before any
court, Governmental Authority or arbitrator that could reasonably be
expected to materially and adversely affect the financial condition or
operations of the Generator or the ability of the Generator to perform
its obligations hereunder, or that purports to affect the legality,
validity or enforceability of this Agreement.
23.2 EGAT represents and warrants to the Generator as follows:
(a) EGAT is a juristic person duly established pursuant to the EGAT Act
and is duly organized and validly existing under the laws of Thailand
and has the full legal right, power and authority to conduct its
business, to own its properties and to execute, deliver and perform
its obligations under this Agreement.
(b) The execution, delivery and performance by EGAT of this Agreement has
been duly authorized by all necessary action, and does not and will
not (i) require any consent or approval of EGAT's Board of Directors
or any other third party, other than those that have been obtained
(evidence of which shall be, if it has not already been, delivered to
the Generator), or (ii) result in a breach of, or constitute a default
under, any provisions of EGAT's constitutive or enabling documents,
any indenture, contract or agreement to which it is a party or by
which it or its assets may be bound, or violate any law, rule,
regulation, order, writ, judgment, injunction, decree, determination
or award at present in effect having applicability to EGAT.
(c) No Governmental Approval by any Governmental Authority or pursuant to
any Law in effect on the date hereof, other than those that have been
obtained, or are
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to be obtained, is necessary for the due execution, delivery and
performance by EGAT of this Agreement.
(d) This Agreement constitutes a legal, valid and binding obligation of
EGAT and is enforceable against EGAT in accordance with its terms.
(e) There is no pending or, to the best of EGAT's knowledge, threatened
action or proceeding affecting EGAT before any court, Governmental
Authority or arbitrator that could reasonably be expected to
materially and adversely affect the financial condition or operations
of EGAT or the ability of EGAT to perform its obligations hereunder,
or that purports to affect the legality, validity or enforceability of
this Agreement.
24. EQUITY UNDERTAKING
24.1 RESTRICTIONS ON TRANSFERABILITY
24.1.1 Subject to Section 24.2, the Generator shall ensure that after the
Execution Date and until the first anniversary of the Commercial
Operation Date of the Second Unit, no Sponsor (or any of its
respective Affiliates) shall transfer any of its equity ownership
interest in the Generator:
(a) to any Affiliate, other Sponsor or other Person if such
transfer will reduce such Sponsor's (or such Sponsor's
Affiliates') equity ownership interest in the Generator to
fifty percent (50%) or less of its equity ownership interest
in the Generator existing on the Execution Date; and
(b) to any Person other than such Sponsor's Affiliates or the
other Sponsors without the prior written approval of EGAT,
such approval not to be unreasonably withheld or delayed.
24.1.2 Subject to Section 24.2, the Generator shall ensure that after the
first anniversary of the Commercial Operation Date of the Second
Unit until the fifth (5th) anniversary of such date, no Sponsor (or
any of its respective Affiliates) shall transfer any of its equity
ownership interest in the Generator:
(a) to any Affiliate, other Sponsor or other Person if such
transfer will reduce such Sponsor's (or such Sponsor's
Affiliates') equity ownership interest in the Generator to
twenty-five percent (25%) or less of its aggregate equity
ownership interest in the Generator existing on the Execution
Date; or
(b) to any Person other than such Sponsor's Affiliates or the
other Sponsors without the prior written approval of EGAT,
such approval not to be unreasonably withheld or delayed.
24.2 QUALIFICATIONS TO EQUITY TRANSFER RESTRICTIONS
During the periods that the restrictions set out in Section 24.1 are
applicable:
(a) EGAT shall be given at least fourteen (14) days' prior notice of any
transfer by a Sponsor (or any of its Affiliates) of any interest in
the Generator to any other Person;
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(b) any Sponsor or transferee of such Sponsor shall have the right to
transfer its interest in the Generator notwithstanding the
restrictions set out in Section 24.1 above so long as such transfer is
approved in writing by EGAT, such approval to be made or withheld at
EGAT's sole discretion;
(c) any Sponsor or transferee of such Sponsor shall have the right to
pledge its direct or indirect interest in the Generator by way of
security to any of the Financing Parties or to any insurer of the
investment in the Project, notwithstanding the restrictions set out in
Section 24.1 above; and
(d) any transferee shall be subject to the same conditions imposed hereby
on transfers made by it as are imposed with respect to transfers by
the Sponsors except a transferee who acquires shares in the Generator
pursuant to an initial public offering of such shares which conforms
to the requirements of the Securities Exchange Commission of Thailand.
25. MISCELLANEOUS PROVISIONS
25.1 AMENDMENTS
This Agreement may not be amended except by an agreement in writing signed
by the Parties.
25.2 WAIVERS OF RIGHTS
25.2.1 No delay or forbearance by either Party in exercising any right,
power, privilege or remedy under this Agreement shall operate to
impair or be construed as a waiver of such right, power, privilege
or remedy. For the avoidance of doubt any waiver by either Party of
the obligations of the other Party shall be evidenced by an
agreement in writing signed by the Parties. Any single or partial
exercise of any such right, power, privilege or remedy shall not
preclude any other or further exercise thereof or the exercise of
any other right, power, privilege or remedy.
25.2.2 The obligations of the Parties hereunder are civil and commercial
in nature rather than governmental. To the extent that either Party
may be or hereafter become entitled, in any jurisdiction, to claim
for itself or its property, assets or revenues immunity (whether by
reason of sovereignty or otherwise) in respect of its obligations
under this Agreement from service of process, suit, jurisdiction of
any court, judgment, order, award, attachment (before or after
judgment or award), set-off, execution of a judgment or other legal
process, and to the extent that in any such jurisdiction there may
be attributed to either Party or to any of such Party's property,
assets or revenues such an immunity (whether or not claimed), each
Party hereby irrevocably agrees not to claim and hereby irrevocably
waives such immunity to the fullest extent permitted by the laws of
such jurisdiction.
25.3 NOTICE
25.3.1 Save for Notices which are given pursuant to the Grid Code (as to
which the procedures provided for in the Grid Code shall apply) or
Section 5, any notice or other communications to be given by one
Party to the other under, or in connection with the matters
contemplated by, this Agreement shall be sent to
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the address given and marked for the attention of the Person
specified in Schedule 5 or such other address or facsimile number
of such Person whom one Party shall from time to time designate by
written notice to the other.
25.3.2 Save for Notices which are given pursuant to the Grid Code, any
notice or other communication to be given by one Party to the other
Party under, or in connection with the matters contemplated by,
this Agreement shall be in writing and shall be given by letter
delivered by hand or sent by first class prepaid post (airmail if
from abroad) or facsimile transmission, and shall be deemed to have
been received:
(a) in the case of delivery by hand, when delivered;
(b) in the case of first class prepaid post, on the third day
following the day of posting or (if sent by airmail from
abroad) on the sixth day after the day of posting; or
(c) in the case of facsimile transmission at the time of
receipt.
25.4 ASSIGNMENT
25.4.1 Neither Party shall assign any of its rights or obligations, in
part or in whole, under this Agreement without the prior written
consent of the other Party, provided that such consent shall not be
withheld or delayed if the Party wishing to assign has demonstrated
to the reasonable satisfaction of the other Party that the proposed
assignee has adequate legal, financial and technical status and
ability to observe and perform the obligations of the assignor
under this Agreement.
25.4.2 No assignment pursuant to Section 25.4.1 shall be effective unless
and until the assignor has procured the proposed assignee to
covenant directly with the other Party to observe and perform all
the terms and conditions of this Agreement, and has provided to the
other Party a certified copy of the assignment (omitting the
consideration therefor and any other commercial terms thereof).
25.4.3 No assignment pursuant to Section 25.4.1 shall be effective unless
at the same time there is assigned or novated to the assignee the
assignor's interest in this Agreement, and any other agreements
between the Parties that are necessary to the Facility or its
operation.
25.4.4 The preceding provisions of this Section 25.4 shall not apply to an
assignment by the Generator of its right, title and interest in and
to the Facility or this Agreement by way of security to any
Financing Party in accordance with the Financing Documents. EGAT
agrees to negotiate with the Generator and the Financing Parties in
good faith for the purposes of entering into (i) a consent to the
collateral assignment of this Agreement, and (ii) a consent to
provide for the security of Financing Parties (including rights and
appropriate time to cure the Generator's defaults) which the
Generator may reasonably request and which does not materially
adversely affect the rights of EGAT hereunder, provided that the
Generator will reimburse EGAT for all reasonable costs and expenses
incurred in relation thereto. Any assignment permitted under this
Section 25.4.4 shall be substantially in the form set out in
Schedule 19.
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25.4.5 Notwithstanding the foregoing provisions of Section 25.4.4, as a
condition to any such consent EGAT shall require that:
(a) any substitute for the Generator under this Agreement that may
be appointed by the Financing Parties, or any designee or
transferee of the Financing Parties or any purchaser of the
Generator or of any of its rights, title and interest under
this Agreement from the Financing Parties upon a foreclosure
sale or other exercise by them of their security under the
Financing Documents, shall have adequate legal, financial and
technical status and ability to observe and perform the
obligations of the Generator under this Agreement;
(b) any such substitute, designee, transferee or purchaser shall
agree in writing to be bound by all the terms, conditions and
provisions of this Agreement; and
(c) the Financing Parties shall have given EGAT at least thirty
(30) days' prior notice of the assignment. EGAT shall have the
right to reject such assignment if it does not conform to the
conditions set out herein.
25.4.6 Unless expressly agreed to by the other Party, no assignment,
whether or not consented to, shall relieve the assignor of its
obligations hereunder if its assignee fails to perform.
25.5 EFFECT OF ILLEGALITY
If for any reason whatsoever any provision of this Agreement is or becomes
invalid, illegal or unenforceable, or is declared by any court of competent
jurisdiction or any other Governmental Authority to be invalid, illegal or
unenforceable or if such Governmental Authority:
(a) refuses or formally indicates an intention to refuse, authorization of
any of the provisions of or arrangements contained in this Agreement
(in the case of a refusal either by way of outright refusal or by way
of a requirement that this Agreement be amended or any of its
provisions be deleted or that a Party give an undertaking or accept a
condition as to future conduct); or
(b) formally indicates that to continue to operate any provision of this
Agreement may expose the Parties to sanctions under any law, order,
enactment or regulation, or requests any Party to give undertakings or
to accept conditions as to future conduct in order that such Party may
not be subject to such sanctions; and, in all cases, whether initially
or at the end of any earlier period or periods of exemption then, in
any such case, the Parties will negotiate in good faith with a view to
agreeing one or more provisions which may be substituted for such
invalid, unenforceable or illegal provision which substitute
provisions are satisfactory to all relevant Governmental Authorities
and produce as nearly as is practicable in all the circumstances the
appropriate balance of the commercial interests of both Parties. The
remaining provisions of this Agreement shall remain in full force and
effect and shall not be affected by such invalid, illegal or
unenforceable provision.
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25.6 ENTIRE AGREEMENT
This Agreement and the "Agreement regarding Power Purchase Agreement"
entered into between the Parties on the date hereof contain or expressly
refer to the entire agreement between the Parties with respect to its
subject matter and expressly excludes any warranty, condition or other
undertaking implied at Law or by custom and supersedes any and all
previous agreements and understandings between the Parties with respect to
its subject matter. Each of the Parties acknowledges and confirms that it
does not enter into this Agreement in reliance on any representation,
warranty or other undertaking by the other Party not fully reflected in
the terms of this Agreement.
25.7 COUNTERPARTS
This Agreement is executed in two (2) original copies, one each for EGAT
and the Generator, each of which when executed and delivered shall
constitute an original, but both counterparts shall together constitute
but one and the same instrument.
25.8 CURRENCY
All payments to be made by either Party to the other Party hereunder shall
be in Baht.
25.9 LANGUAGE
This Agreement is being executed and delivered in the English language and
all modifications, amendments and waivers of and notices given pursuant to
any provision of this Agreement shall be in the English language. All
other documents, notices and communications, written or otherwise, between
the Parties in connection with this Agreement, shall be in either English
or Thai language as the Parties deem practicable. However, the Parties
agree that the Grid Code shall be in the English language and the
communications related thereto shall be in either English or Thai as
appropriate.
25.10 THIRD PARTIES
This Agreement is intended solely for the benefit of the Parties. This
Agreement shall be binding upon and inure to the benefit of the Parties
and their respective successors and permitted assignees. Nothing in this
Agreement should be construed to create any duty or liability to, or
standard of care with reference to, any third parties.
25.11 INCONSISTENCIES AND CONFLICTS
25.11.1 In the event of any inconsistency or conflict between the
provisions of this Agreement and the Grid Code, the provisions of
the Grid Code shall prevail.
25.11.2 In the event of any inconsistency or conflict referred to in
Section 25.11.1 existing at the date of this Agreement or arising
subsequently, the Parties shall, without prejudice to their rights
in respect of a change in the Grid Code, seek to negotiate an
amendment to this Agreement which removes the inconsistency or
conflict. If the Parties cannot agree on what amendment should be
made to this Agreement the dispute shall be referred to an Expert.
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26. GOVERNING LAW AND JURISDICTION
26.1 GOVERNING LAW
This Agreement shall be governed by and construed in all respects in
accordance with the laws of Thailand.
26.2 WAIVER
Each Party irrevocably waives any objection which it may have now or
hereafter to the laying of the venue of any proceedings in any court and
any claim that any such proceedings have been brought in an inconvenient
forum, and further irrevocably agrees that a judgment in any proceedings
brought in the courts of Thailand shall be conclusive and binding upon such
Party and may be enforced in the courts of any other jurisdiction.
26.3 ARBITRATION
For the avoidance of doubt, all disputes arising under or in connection
with this Agreement shall be resolved in accordance with Section 15 and
nothing contained in Section 26.1 or 26.2 shall be construed as permitting
either Party to commence proceedings in any court in any jurisdiction
except as may be necessary to enforce an arbitration award or the final
determination of a dispute by an Expert.
27. PRIVATIZATION OF EGAT
27.1 The Parties acknowledge that it is the present intention of the Government
of Thailand to corporatize and eventually privatize EGAT. At such time that
(i) EGAT shall have been privatized, and (ii) the Government of Thailand
and all other Governmental Authorities shall cease to Control EGAT, then
the Parties shall use their best efforts to obtain the Financing Parties'
approval to delete the definition of Governmental Force Majeure and the
provisions of this Agreement regarding Governmental Force Majeure, it being
the intention of the Parties and the Financing Parties that the need for
such provisions would then not be appropriate, and EGAT shall not bear the
risk of Governmental Force Majeure as provided for in this Agreement. The
events, conditions and circumstances previously described as Governmental
Force Majeure shall nevertheless continue to constitute Force Majeure.
28. PERMISSION UNDER EGAT ACT
28.1 This Agreement is the permission issued by EGAT to the Generator pursuant
to Section 37 of the EGAT Act, and this permission shall remain valid
throughout the Term of this Agreement. Except for those stated in this
Agreement, there is no other condition to such permission.
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IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed
by their respective duly authorized officers as of the date first above
written.
ELECTRICITY GENERATING AUTHORITY OF
THAILAND
Witness:_____________________________ By:___________________________
(Mr. Viroj Nopkhun) (Mr. Viravat Chlayon)
Deputy-Governor-Planning and Policy Governor
GULF POWER GENERATION CO., LTD.
Witness:_____________________________ By:___________________________
(Mr. Robert M. Edgell) (Mr. Sarath Ratanavadi)
Director Director
By:___________________________
(Mr Gerard P. Loughman)
Director
Page 77
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EXHIBIT 21
EDISON MISSION ENERGY
SUBSIDIARIES AND PARTNERSHIPS
-----------------------------
As of March 13, 1998
Domestic
- --------
Aguila Energy Company (LP)
American Bituminous Power Partners, L.P. (Delaware limited partnership)
American Kiln Partners, Limited Partnership (Delaware Limited
partnership)
Anacapa Energy Company (GP)
Salinas River Cogeneration Company (Partnership)
Arrowhead Energy Company
Balboa Energy Company (GP)
Smithtown Cogeneration, L.P. (Delaware Partnership)
Bergen Point Energy Company (GP)
TEVCO/Mission Bayonne Partnership (Delaware general partnership)
Blue Ridge Energy Company (GP)
Bretton Woods Cogeneration, L.P. (Delaware limited partnership)
Bretton Woods Energy Company (GP & LP)
Bretton Woods Cogeneration, L.P. (Delaware limited partnership)
Camino Energy Company (GP)
Watson Cogeneration Company (Partnership)
Capistrano Cogeneration Company (GP)
James River Cogeneration Company (North Carolina Partnership)
Centerport Energy Company (GP & LP)
Riverhead Cogeneration I, L.P. (Delaware Partnership)
Chesapeake Bay Energy Company (formerly Woodland Energy Company) (GP)
Delaware Clean Energy Project (Delaware General Partnership)
Chester Energy Company
Holds option to purchase piece of property (vacant land) located in or near
Richmond/ Chesapeake, Virginia
Clayville Energy Company
Oconee Energy, L.P. (Delaware limited partnership)
Colonial Energy Company (formerly Hentland Farm Energy Company)-Inactive
Coronado Energy Company
Oconee Energy, L.P.
Crescent Valley Energy Company (Inactive)
Delaware Energy Conservers, Inc. (Delaware corporation) - Inactive
Del Mar Energy Company (GP)
Mid-Set Cogeneration Company (Partnership)
Desert Sunrise Energy Company (Nevada Corporation) - Inactive
Devereaux Energy Company (LP)
Auburndale Power Partners, Limited Partnership (Delaware limited
partnership)
East Maine Energy Company (Inactive)
Eastern Sierra Energy Company (GP & LP)
Saguaro Power Company, A Limited Partnership (Partnership)
Edison Mission Energy Funding Corp. (Delaware corporation)
Edison Mission Energy Interface Ltd. (Canadian company)
The Mission Interface Partnership
1
<PAGE>
Edison Mission Operation & Maintenance, Inc.
Mission Operations de Mexico, S.A. de C.V.
El Dorado Energy Company (GP)
Auburndale Power Partners, Limited Partnership (Delaware limited
partnership)
EMP, Inc. (Oregon Corporation) (GP & LP)
GEO East Mesa Limited Partnership (Partnership)
GEO East Mesa Electric Company (Nevada corporation)
Four Counties Gas Company (Inactive)
Hanover Energy Company
Chickahominy River Energy Corp.
Commonwealth Atlantic Limited Partnership (Delaware Partnership)
Holtsville Energy Company (GP & LP)
Brookhaven Cogeneration, L.P. (Delaware Partnership)
Indian Bay Energy Company (GP & LP)
Riverhead Cogeneration III, L.P. (Delaware Partnership)
Jefferson Energy Company (GP & LP) (Inactive)
Kings Canyon Energy Company (Inactive)
Kingspark Energy Company (GP & LP)
Smithtown Cogeneration, L.P. (Delaware Partnership)
Laguna Energy Company (Inactive)
La Jolla Energy Company (Inactive)
Lake Grove Energy Company (Inactive)
Lakeview Energy Company
Georgia Peakers, L.P. (Delaware partnership)
Lehigh River Energy Company (GP)
Longview Cogeneration Company (formerly Columbia River Cogeneration Company and
prior to that, formerly Cabrillo Energy Company) - Inactive
Madera Energy Company (GP)
Brookhaven Cogeneration , L.P. (Delaware Partnership)
Madison Energy Company (formerly Sunshine Generators, Inc.) (LP)
Gordonsville Energy L. P. (Delaware partnership)
Mission/Eagle Energy Company
Mission Energy Construction Services, Inc. (formerly Glenwood Springs Property,
Inc.)
Edison Mission Energy Fuel
Edison Mission Energy Oil and Gas
Four Star Oil & Gas Company
Edison Mission Energy Petroleum
Pocono Fuels Company (Inactive)
Southern Sierra Gas Company
TM Star Fuel Company (California general partnership)
Mission Energy Holdings, Inc.
Mission Capital, L.P. (Delaware limited partnership) owned 97%/3% by EME
respectively
Mission Energy Holdings International, Inc. (formerly Patapsco Energy Company)
(Owns 100% of MEC International B.V.)
Mission Energy Indonesia (formerly Chula Energy Company) - Inactive
Mission Energy Mexico (Inactive)
2
<PAGE>
Mission Energy New York, Inc. (formerly, Allegheny Energy Company) (GP & LP)
Brooklyn Navy Yard Cogeneration Partners, L.P. (Delaware Partnership)
Mission Energy Wales Company (formerly San Jacinto Energy Company)
Mission Hydro Limited Partnership (UK limited partnership)
Mission Energy Westside, Inc. (formerly Sun Coast Energy Company) - Inactive
Mission Triple Cycle Systems Company (GP)
Triple Cycle Partnership (Texas general partnership)
Northern Sierra Energy Company (GP)
Sobel Cogeneration Company (California general partnership)
North Jackson Energy Company (Inactive)
Ortega Energy Company
Panther Timber Company (GP)
American Kiln Partners, Limited Partnership (Delaware limited partnership)
Paradise Energy Company - Inactive
Pleasant Valley Energy Company (GP)
American Bituminous Power Partners, L.P. (Delaware Partnership)
Prince George Energy Company (LP)
Hopewell Cogeneration Limited Partnership (Delaware partnership)
Hopewell Cogeneration Inc. (Delaware corporation)
Hopewell Cogeneration Limited Partnership (Delaware partnership)
Quartz Peak Energy Company (LP)
Nevada Sun-Peak Limited Partnership (Nevada partnership)
Rapidan Energy Company (GP)
Gordonsville Energy, L.P. (Delaware Partnership)
Reeves Bay Energy Company (GP & LP)
North Shore Energy, L.P. (Delaware Partnership)
Northville Energy Corporation (New York corporation)
Ridgecrest Energy Company (GP)
Riverhead Cogeneration I, L.P. (Delaware Partnership)
Rio Escondido Energy Company - Inactive
Riverport Energy Company (GP & LP)
Riverhead Cogeneration II, L.P. (Delaware Partnership)
San Gabriel Energy Company (Inactive)
San Joaquin Energy Company (GP)
Midway-Sunset Cogeneration Company, L.P. (Partnership)
San Juan Energy Company (GP)
March Point Cogeneration Company (Partnership)
San Pedro Energy Company (GP)
Riverhead Cogeneration II, L.P. (Delaware Partnership)
Santa Ana Energy Company (GP)
Riverhead Cogeneration III, L.P. (Delaware Partnership)
Santa Clara Energy Company (GP)
North Shore Energy, L.P. (Delaware Partnership)
Northville Energy Corporation (New York corporation)
Silverado Energy Company (GP)
Coalinga Cogeneration Company (Partnership)
Silver Springs Energy Company
Georgia Peaker, L.P. (Delaware limited partnership)
3
<PAGE>
Sonoma Geothermal Company (GP & LP)
Geothermal Energy Partners Ltd. (California partnership)
South Coast Energy Company (GP)
Harbor Cogeneration Company (Partnership)
Southern Sierra Energy Company (GP)
Kern River Cogeneration Company (California general partnership)
Thorofare Energy Company
Viejo Energy Company (GP)
Sargent Canyon Cogeneration Company (Partnership)
Vista Energy Company (New Jersey Corporation) (GP & LP)
Western Sierra Energy Company (GP)
Sycamore Cogeneration Company (California general partnership)
International
- -------------
Edison Mission Energy Asia Pte. Ltd. (formerly Mission Energy Asia Pte. Ltd.)
(Singapore)
Edison Mission Energy Asia Pacific Pte. Ltd. (Singapore)
Edison Mission Energy Fuel Company Pte. Ltd. (Singapore)
Edison Mission Operation and Maintenance Services Pte. Ltd. (Singapore)
P.T. Edison Mission Operation and Maintenance Indonesia (Indonesia)
Edison Mission Energy Holdings Pty Ltd (Australia) (formerly Mission Energy
Holdings Pty Ltd)
Edison Mission Operation & Maintenance Kwinana Pty Ltd (formerly Mission
Operations (Kwinana) Pty Ltd (Australia)
Edison Mission Operation & Maintenance Loy Yang Pty. Ltd. (formerly Mission
Energy Management Australia Pty. Ltd.) (Australia)
Mission Energy Development Australia Pty. Ltd.
Mission Energy Holdings Superannuation Fund Pty Ltd.
Mission Energy (Kwinana) Pty Ltd
Kwinana Power Partnership (Australian G.P.)
Edison Mission Energy International B.V. (formerly MEC Mission B.V.)
(Netherlands)
Edison Mission Energy Power (Mauritius)
EME Victoria B.V. (Inactive)
Hydro Energy B.V. (Netherlands company)
Edison Mission Energy Espana (formerly Energias Hidraulicas, S.A.) (Spain
corporation)
Iberica de Energias, S.A. (Spain corporation)
Electrometalurgica del Ebro, S.A. (Spain corporation)
Monasterio de Rueda, S.L. (inactive)
Iberian Hy-Power Amsterdam, B.V. (Netherlands Antilles corporation)
Hidroelectrica de Olvera, S.A. (Spain corporation)
Hidroelectrica del Sossis, S.A. (Spain corporation)
Loy Yang Holdings Pty Ltd (Australia)
Edison Mission Energy Holdings Pty Ltd (Australia)
Mission Energy Holdings Superannuation Fund Pty Ltd.Edison Mission
Energy Australia Ltd (formerly Mission Energy Australia Ltd. (an
Australian public company)
Edison Mission Operation &Maintenance Kwinana Pty. Ltd.
Edison Mission Operation & Maintenance Loy Yang Pty. Ltd.
Mission Energy (Kwinana) Pty. Ltd.
Edison Mission Energy Australia Ltd.
4
<PAGE>
Mission Energy Ventures Australia Pty. Ltd.
Latrobe Power Pty
Mission Victoria Partnership
Latrobe Power Partnership
Loy Yang Joint Venture
MEC Esenyurt B.V. (Netherlands)
Doga Enerji Uretim Sanayi ve Ticaret A.S. (Turkish corporation)
Doga Isi Satis Hizmetleri Ticaret L.S.
Doga Isletme ve Bakim Ticaret L.S.
MEC IES B.V. (Netherlands) formerly MEC ESA B.V.
ISAB Energy Services s.r.l. (Operator of ISAB )
MEC India B.V. (Netherlands)
Edison Mission Energy Power (Mauritius corporation)
MEC Indo Coal B.V. (Netherlands)
P.T. Adaro Indonesia (Indonesia)
MEC Indonesia B.V. (Netherlands)
P.T. Paiton Energy Company (Indonesia)
MEC International Holdings B.V.(Netherlands)
MEC Laguna Power B.V. (Netherlands company)
Gulf Power Generation Co. Ltd. (Bangkok corporation)
MEC Perth B.V. (Netherlands)
Kwinana Power Partnership (Australian GP)
MEC Priolo B.V. (Netherlands)
ISAB Energy S.r.l.
MEC San Pascual B.V. (Netherlands)
San Pascual Cogeneration Company International B.V.
MEC Sidi Krir (formerly MEC Colombia B.V.) (Netherlands)
MEC Wales B.V. (Netherlands)
Mission Hydro Limited Partnership (UK)
EME Generation Holdings Ltd.
EME Victoria Generation Ltd.
Mission Energy Development Australia Pty Ltd
Gippsland Power Pty Ltd
Energy Capital Partnership
Enerloy Pty Ltd
Mission Energy Italia s.r.l. (Rep. office in Italy)
P.T. Mission Operation and Maintenance Indonesia (Indonesian company)
Mission Energy Interface Ltd. (Canadian company)
The Mission Interface Partnership (Province of Ontario general partnership)
Mission Energy Company (UK) Limited (UK private limited company)
Derwent Cogeneration Limited (UK private limited company)
Edison Mission Energy Limited (UK private limited company)
Mission Energy Services Limited (UK private limited company)
Mission (No. 2) Limited (UK private limited company)
Pride Hold Ltd. (UK corporation)
Lakeland Power Development Company (UK corporation)
Lakeland Power Ltd. (UK corporation)
Mission Hydro (UK) Ltd.
Mission Hydro Ltd. Partnership (UK)
First Hydro Holdings Company
First Hydro Finance plc
First Hydro Company
P.T. Edison Mission Operation and Maintenance Indonesia (Indonesia)
5
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM EDISON
MISSION ENERGY AND SUBSIDIARIES FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
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150,000
0
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